Amplify Energy (AMPYW) 8-K Memorial Production Partners LP

Exhibit 99.2

RECAST ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MEMORIAL PRODUCTION PARTNERS LP

INDEX TO SUPPLEMENTAL FINANCIAL STATEMENTS

	Page No.
Report of Independent Registered Public Accounting Firm	F-2
Supplemental Consolidated and Combined Balance Sheets as of December 31, 2014 and 2013	F-3
Statements of Supplemental Consolidated and Combined Operations for the Years Ended December 31, 2014, 2013, and 2012	F-4
Statements of Supplemental Consolidated and Combined Cash Flows for the Years Ended December 31, 2014, 2013, and 2012	F-5
Statements of Supplemental Consolidated and Combined Equity for the Years Ended December 31, 2014, 2013, and 2012	F-6
Notes to Supplemental Consolidated and Combined Financial Statements
Note 1 – Organization and Basis of Presentation	F-7
Note 2 – Summary of Significant Accounting Policies	F-8
Note 3 – Acquisitions and Divestitures	F-14
Note 4 – Fair Value Measurements of Financial Instruments	F-17
Note 5 – Risk Management and Derivative Instruments	F-19
Note 6 – Asset Retirement Obligations	F-22
Note 7 – Restricted Investments	F-23
Note 8 – Long Term Debt	F-23
Note 9 – Equity & Distributions	F-27
Note 10 – Earnings per Unit	F-32
Note 11 – Equity-based Awards	F-32
Note 12 – Related Party Transactions	F-33
Note 13 – Commitments and Contingencies	F-39
Note 14 – Defined Contribution Plans	F-40
Note 15 – Income Tax	F-41
Note 16 – Quarterly Financial Information (Unaudited)	F-43
Note 17 – Supplemental Oil and Gas Information (Unaudited)	F-43
Note 18 – Subsequent Event	F-46

F- 1

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 supplemental consolidated and combined balance sheets of Memorial Production Partners LP and subsidiaries (the Partnership) as of December 31, 2014 and 2013, and the related supplemental consolidated and combined statements of operations, equity, and cash flows for each of the years in the three‑year period ended December 31, 2014. These supplemental consolidated and combined financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these supplemental consolidated and combined 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, the supplemental consolidated and combined financial statements referred to above present fairly, in all material respects, the financial position of Memorial Production Partners LP and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three‑year period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

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

/s/ KPMG LLP

Dallas, Texas

April 21, 2015

F- 2

MEMORIAL PRODUCTION PARTNERS LP

SUPPLEMENTAL CONSOLIDATED AND COMBINED BALANCE SHEETS

(In thousands, except outstanding units)

	December 31,			December 31,
	2014*			2013*
ASSETS
Current assets:
Cash and cash equivalents	$	970		$	21,698
Accounts receivable:
Oil and natural gas sales		46,413			33,652
Joint interest owners and other (Note 2)		36,937			5,110
Affiliates		—			4,473
Short-term derivative instruments		208,585			7,600
Prepaid expenses and other current assets		14,201			9,944
Total current assets		307,106			82,477
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		3,329,338			2,079,304
Support equipment and facilities		198,088			16,030
Other		3,020			2,905
Accumulated depreciation, depletion and impairment		(1,060,114	)		(464,812	)
Property and equipment, net		2,470,332			1,633,427
Long-term derivative instruments		311,802			42,657
Restricted investments		77,361			73,385
Other long-term assets		23,159			17,422
Total assets	$	3,189,760		$	1,849,368
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	23,609		$	8,922
Accounts payable - affiliates		6,409			747
Revenues payable		30,110			19,355
Accrued liabilities (Note 2)		90,974			46,842
Short-term derivative instruments		3,289			7,996
Total current liabilities		154,391			83,862
Long-term debt (Note 8)		1,595,413			792,067
Asset retirement obligations		112,702			101,436
Long-term derivative instruments		—			5,875
Deferred tax liabilities		30,940			3,107
Total liabilities		1,893,446			986,347
Commitments and contingencies (Note 13)
Equity:
Partners' equity (deficit):
Common units (80,421,992 units outstanding at December 31, 2014 and 55,877,831 units outstanding at December 31, 2013)		1,085,265			582,075
Subordinated units (5,360,912 units outstanding at December 31, 2014 and 2013)		(16,419	)		(8,715	)
General partner (86,797 units outstanding at December 31, 2014 and 61,300 units outstanding at December 31, 2013)		1,251			728
Previous owners		220,657			283,405
Total partners' equity		1,290,754			857,493
Noncontrolling interests		5,560			5,528
Total equity		1,296,314			863,021
Total liabilities and equity	$	3,189,760		$	1,849,368

See Accompanying Notes to Supplemental Consolidated and Combined Financial Statements.

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

F- 3

MEMORIAL PRODUCTION PARTNERS LP

STATEMENTS OF SUPPLEMENTAL CONSOLIDATED AND COMBINED OPERATIONS

(In thousands, except per unit amounts)

	For the Year Ended
	December 31,
	2014*			2013*			2012*
Revenues:
Oil & natural gas sales	$	531,853		$	370,062		$	289,912
Pipeline tariff income and other		4,366			3,075			3,253
Total revenues		536,219			373,137			293,165
Costs and expenses:
Lease operating		143,733			96,433			87,972
Pipeline operating		2,068			1,835			2,114
Exploration		2,750			1,322			9,340
Production and ad valorem taxes		33,141			18,447			15,354
Depreciation, depletion, and amortization		185,955			113,814			101,624
Impairment of proved oil and natural gas properties		407,540			4,072			22,994
General and administrative		49,124			54,947			35,112
Accretion of asset retirement obligations		5,773			4,988			4,458
(Gain) loss on commodity derivative instruments		(492,254	)		(26,133	)		(24,405	)
(Gain) loss on sale of properties		—			(2,848	)		(9,759	)
Other, net		(11	)		647			38
Total costs and expenses		337,819			267,524			244,842
Operating income (loss)		198,400			105,613			48,323
Other income (expense):
Interest expense, net		(83,550	)		(44,302	)		(24,955	)
Other income (expense)		(657	)		2			1
Amortization of investment premium		—			—			(194	)
Total other income (expense)		(84,207	)		(44,300	)		(25,148	)
Income (loss) before income taxes		114,193			61,313			23,175
Income tax benefit (expense)		1,421			(308	)		(108	)
Net income (loss)		115,614			61,005			23,067
Net income (loss) attributable to noncontrolling interest		32			267			104
Net income (loss) attributable to Memorial Production Partners LP	$	115,582		$	60,738		$	22,963
Limited partners' interest in net income (loss):
Net income (loss) attributable to Memorial Production Partners LP	$	115,582		$	60,738		$	22,963
Net (income) loss allocated to previous owners		2,465			(52,012	)		(22,842	)
Net (income) loss allocated to general partner		(206	)		(49	)		—
Net (income) loss allocated to NGP IDRs		(88	)		—			—
Limited partners' interest in net income (loss)	$	117,753		$	8,677		$	121
Earnings per unit: (Note 10)
Basic and diluted earnings per unit	$	1.66		$	0.19		$	0.01
Weighted average limited partner units outstanding:
Basic and diluted		70,859			46,017			22,880

See Accompanying Notes to Supplemental Consolidated and Combined Financial Statements.

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

F- 4

MEMORIAL PRODUCTION PARTNERS LP

STATEMENTS OF SUPPLEMENTAL CONSOLIDATED AND COMBINED CASH FLOWS

(In thousands)

	For the Year Ended
	December 31,
	2014*			2013*			2012*
Cash flows from operating activities:
Net income (loss)	$	115,614		$	61,005		$	23,067
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization		185,955			113,814			101,624
Impairment of proved oil and natural gas properties		407,540			4,072			22,994
(Gain) loss on derivative instruments		(492,405	)		(26,681	)		(19,566	)
Cash settlements (paid) received on derivative instruments		11,693			22,678			51,755
Premiums paid for derivatives		—			—			(411	)
Deferred income tax expense (benefit)		(1,548	)		—			(177	)
Amortization of deferred financing costs		4,227			6,013			2,706
Accretion of senior notes net discount		1,921			504			—
Amortization of investment premium		—			—			194
Accretion of asset retirement obligations		5,773			4,988			4,458
Amortization of equity awards		7,874			3,558			1,423
Gain on sale of properties		—			(2,848	)		(9,759	)
Exploration costs		1,960			95			6,913
Non-cash compensation expense		—			1,057			—
Changes in operating assets and liabilities:
Accounts receivable		(18,022	)		1,269			(804	)
Prepaid expenses and other assets		(2,695	)		(1,052	)		(796	)
Payables and accrued liabilities		27,037			12,999			765
Other		(651	)		232			(403	)
Net cash provided by operating activities		254,273			201,703			183,983
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(1,083,761	)		(38,664	)		(277,623	)
Additions to oil and gas properties		(298,274	)		(174,821	)		(168,411	)
Additions to restricted investments		(3,976	)		(5,361	)		(4,599	)
Additions to other property and equipment		(98	)		(238	)		(1,748	)
Proceeds from the sale of oil and natural gas properties		—			4,525			34,521
Other		—			—			29
Net cash used in investing activities		(1,386,109	)		(214,559	)		(417,831	)
Cash flows from financing activities:
Advances on revolving credit facilities		1,446,000			958,355			496,500
Payments on revolving credit facilities		(1,137,000	)		(1,565,537	)		(226,819	)
Deferred financing costs		(11,494	)		(20,924	)		(2,392	)
Proceeds from senior notes		492,425			688,563			—
Capital contributions from previous owners		5,990			96,803			64,597
Contributions related to sale of assets to NGP affiliate		—			2,013			38,125
Proceeds from general partner contribution		570			521			206
Proceeds from the issuance of common units		553,288			511,204			202,572
Costs incurred in conjunction with issuance of common units		(12,510	)		(21,066	)		(8,268	)
Distributions to partners		(154,852	)		(96,643	)		(34,436	)
Distribution to Memorial Resource (see Note 1)		(48,880	)		(151,714	)		(18,489	)
Restricted units returned to plan		(1,012	)		—			—
Distribution to NGP affiliates (see Note 1)		—			(355,495	)		(242,174	)
Repurchases under unit repurchase program		(11,531	)		—			—
Transfer of operating subsidiary to Memorial Resource (see Note 12)		—			—			(3,751	)
Distributions made by previous owners		(9,886	)		(31,098	)		(28,438	)
Cash retained by previous owners		—			(9,013	)		—
Net cash provided by financing activities		1,111,108			5,969			237,233
Net change in cash and cash equivalents		(20,728	)		(6,887	)		3,385
Cash and cash equivalents, beginning of period		21,698			28,585			25,200
Cash and cash equivalents, end of period	$	970		$	21,698		$	28,585

See Accompanying Notes to Supplemental Consolidated and Combined Financial Statements.

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

See Note 2 for Supplemental Cash Flow information

F- 5

MEMORIAL PRODUCTION PARTNERS LP

STATEMENTS OF SUPPLEMENTAL CONSOLIDATED AND COMBINED EQUITY

(In thousands)

	Partner's Equity (Deficit)
	Limited Partners						General			Previous			NGP			Noncontrolling
	Common			Subordinated			Partner			Owners			IDRs			Interest		Total
Balance December 31, 2011*	$	241,034		$	61,708		$	426		$	583,158		$	—		$	5,157	$	891,483
Net income (loss)		114			7			—			22,842			—			104		23,067
Net proceeds from the issuance of common units		194,134			—			—			—			—			—		194,134
Contributions		—			—			206			64,597			—			—		64,803
Contribution of oil and gas properties		—			—			—			6,893			—			—		6,893
Distribution attributable to net assets acquired (Note 1)		(209,720	)		(77,701	)		(242	)		27,000			—			—		(260,663	)
Net book value of net assets acquired (Note 12)		99,972			44,269			94			(144,335	)		—			—		—
Contribution related to sale of assets to NGP affiliate		—			—			—			40,138			—			—		40,138
Net book value of net assets acquired by NGP affiliate		—			—			—			(33,859	)		—			—		(33,859	)
Amortization of equity awards		1,423			—			—			—			—			—		1,423
Distributions		(26,152	)		(8,298	)		(34	)		(28,438	)		—			—		(62,922	)
Deferred tax liability adjustments		335			111			—			—			—			—		446
Other		64			60			—			(204	)		—			—		(80	)
Balance December 31, 2012*		301,204			20,156			450			537,792			—			5,261		864,863
Net income (loss)		7,880			797			49			52,012			—			267		61,005
Net proceeds from the issuance of common units		490,138			—			—			—			—			—		490,138
Contributions		—			—			521			96,803			—			—		97,324
Distribution attributable to net assets acquired (Note 1)		(490,400	)		(67,242	)		(559	)		55,281			—			—		(502,920	)
Net book value of net assets acquired (Note 12)		355,159			48,739			403			(404,301	)		—			—		—
Amortization of equity awards		3,558			—			—			—			—			—		3,558
Distributions		(85,342	)		(11,165	)		(136	)		(31,098	)		—			—		(127,741	)
Other		(122	)		—			—			(2,302	)		—			—		(2,424	)
Net assets retained by previous owners		—			—			—			(20,782	)		—			—		(20,782	)
Balance, December 31, 2013*		582,075			(8,715	)		728			283,405			—			5,528		863,021
Net income (loss)		113,573			4,180			206			(2,465	)		88			32		115,614
Net proceeds from the issuance of common units		540,698			—			—			—			—			—		540,698
Contributions		—			—			570			5,990			—			—		6,560
Distributions		(142,719	)		(11,794	)		(251	)		(9,886	)		(88	)		—		(164,738	)
Distribution attributable to net assets acquired (Note 12)		(2,321	)		(90	)		(2	)		—			—			—		(2,413	)
Distribution of net asset to MRD Holdco		—			—			—			(26,131	)		—			—		(26,131	)
Amortization of equity awards		7,874			—			—			—			—			—		7,874
Tax related effects attributable to Memorial Resource restructuring and initial public offering		—			—			—			(30,483	)		—			—		(30,483	)
Common units repurchased under repurchase program (Note 9)		(12,903	)		—			—			—			—			—		(12,903	)
Restricted units repurchased (See Note 9)		(1,012	)		—			—			—			—			—		(1,012	)
Other		—			—			—			227			—			—		227
Balance, December 31, 2014*	$	1,085,265		$	(16,419	)	$	1,251		$	220,657		$	—		$	5,560	$	1,296,314

See Accompanying Notes to Supplemental Consolidated and Combined Financial Statements.

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

F- 6

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 1. Organization and Basis of Presentation

General

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

The Partnership was formed in April 2011 by Memorial Resource Development LLC (“MRD LLC”) to own, acquire and exploit oil and natural gas properties in North America. Memorial Resource Development Corp. (“MRD”) was formed by MRD LLC in January 2014 to exploit, develop and acquire natural gas and oil properties in North America. MRD LLC was a Delaware limited liability company formed in April 2011 by Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P. (collectively, the “Funds”) to own, acquire, exploit and develop oil and natural gas properties and to own our general partner. In June 2014, (i) the Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”), after which MRD Holdco owned 100% of MRD LLC, and (ii) MRD LLC distributed certain assets, including all of our subordinated units, to MRD Holdco. On June 18, 2014, MRD LLC contributed substantially all of its assets, including its interest in our general partner, to MRD in connection with MRD’s initial public offering. On June 27, 2014, MRD LLC merged into MRD Operating LLC, a subsidiary of MRD. Memorial Resource provides management, administrative, and operations personnel to us and our general partner under an omnibus agreement (see Note 12). The Funds are private equity funds managed by Natural Gas Partners (“NGP”). The Funds collectively indirectly own 50% of our incentive distribution rights (“IDRs”). The remaining IDRs are owned by our general partner.

Unless the context requires otherwise, references to “Memorial Resource” refer collectively to MRD and its subsidiaries other than the Partnership. The Partnership is owned 99.9% by its limited partners and 0.1% by its general partner, Memorial Production Partners GP LLC, which is a wholly owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership’s operations and activities.

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

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

Previous Owners

References to “the previous owners” for accounting and financial reporting purposes refer collectively to:

· Certain oil and natural gas properties the Partnership acquired from MRD LLC in April and May 2012 (“Tanos/Classic Properties”) for periods after common control commenced through their respective date of acquisition.

· Rise Energy Operating, LLC and its wholly-owned subsidiaries (except for Rise Energy Operating, Inc.) (“REO”) from February 3, 2009 (inception) through the date of acquisition. The Partnership acquired REO, which owns certain operating interests in producing and non-producing oil and gas properties offshore Southern California, in December 2012 from Rise Energy Partners, LP (“Rise”). We refer to this transaction as the “Beta acquisition.” Rise was primarily owned by two of the Funds.

· Certain oil and natural gas properties and related assets in East Texas and North Louisiana that the Partnership acquired in March 2013 owned by WHT Energy Partners (“WHT”) (the “WHT Properties”) from February 2, 2011 (inception) through the date of acquisition.

F- 7

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

· Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that the Partnership acquired through equity and asset transactions on October 1, 2013 from both MRD LLC and certain affiliates of NGP as discussed below. We refer to this transaction as the “Cinco Group acquisition.”

· Certain oil and natural gas properties primarily located in East Texas and assets in West Louisiana that the Partnership acquired in February 2015 from certain operating subsidiaries of Memorial Resource in exchange for cash and certain of our oil and natural gas properties primarily located in North Louisiana.  We refer to this transaction as the “Property Swap.”  The acquired East Texas oil and natural gas properties were owned by Classic Hydrocarbons Holdings, L.P. or its subsidiaries (“Classic”).

Each of these aforementioned acquisitions was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information has been retrospectively revised to give effect to such acquisitions as if the Partnership owned the assets for periods after common control commenced through their respective acquisition dates. See Note 12 for additional information.

Basis of Presentation

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

The previous owners combined financial statements reflect: (i) certain oil and gas properties acquired from MRD LLC in April and May 2012 for periods after common control commenced through their respective date of acquisition on a combined basis for all periods presented, (ii) the consolidated financial statements of REO for all periods presented, (iii) the WHT Properties from February 2, 2011 (inception) through the date of acquisition, (iv) the financial statements of Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits overriding royalty interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), Stanolind Oil and Gas SPV LLC (“Stanolind SPV”), Tanos Energy, LLC (“Tanos”), together with its wholly-owned subsidiaries, Prospect Energy, LLC (“Prospect”), and certain oil and natural gas properties in Jackson County, Texas (the “MRD Assets”) (collectively, the “Cinco Group”) on a combined basis for periods after common control commenced through the date of acquisition, and (v) certain oil and gas properties primarily located in the Joaquin Field in Shelby and Panola counties in East Texas and in West Louisiana acquired from Memorial Resource in February 2015 for periods after common control commenced through the date of acquisition.  The Partnership acquired substantially all of the Cinco Group on October 1, 2013 from: (a) Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds, and (b) MRD LLC.

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

All material intercompany transactions and balances have been eliminated in preparation of our supplemental consolidated and combined financial statements. The accompanying supplemental consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Certain amounts in the prior year financial statements have been reclassified to conform to current presentation.

Note 2. Summary of Significant Accounting Policies

Use of Estimates

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

Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value

F- 8

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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

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. Likewise, the combined financial statements include the accounts of the previous owners as discussed above. All material intercompany balances and transactions have been eliminated.

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.

Concentrations of Credit Risk

Cash balances, accounts receivable, restricted investments 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. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These restricted investments consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose 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 rely upon netting arrangements with counterparties to reduce credit exposure. Neither we nor and the previous owners 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 the previous owners. 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, 2014 and 2013, respectively.

If we were to lose any one of our customers, the loss could temporarily delay the production and the 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.

Oil and Natural Gas Properties

Oil and natural gas exploration, development and production activities are accounted for 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. Capitalized drilling and development costs of producing

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves.  Support equipment and facilities are depreciated using the straight-line method generally based on estimated useful lives of fifteen to forty years.

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.

There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2014, 2013 and 2012.

Oil and Gas Reserves

The estimates of proved oil and natural gas reserves utilized in the preparation of the supplemental consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. We engaged Netherland, Sewell & Associates, Inc. (“NSAI”) and Ryder Scott Company, L.P. (“Ryder Scott”), our independent reserve engineers, to audit our internally prepared reserves estimates for approximately 86% of our estimated proved reserves (by volume) at December 31, 2014.

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. 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 decreased. 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 cost 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 generally based on estimated useful lives of three to five years.

Restricted Investments

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense, net in the statement of operations. The amortized cost of such investments is adjusted for amortization of premiums and accretion of discounts to maturity. Such amortization and accretion is displayed as a separate line item in the statement of operations. These restricted investments may consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information.

Debt Issuance Costs

These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method and generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2014, 2013 and 2012 was approximately $4.2 million, $6.0 million, and $2.7 million, respectively.

Impairments

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable.  This may be due to a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted 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

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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, 2014, 2013 and 2012 was approximately $407.5 million, $4.1 million, and $23.0 million, respectively.

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 in net income (loss) to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations.

Book Overdrafts

Book overdrafts, representing outstanding checks in excess of funds on deposit, are classified as accounts payable and the change in the related balance is reflected in operating activities in the statement of cash flows.

Revenue Recognition

Revenue from the sale of oil and natural gas 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 there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2014 or 2013.

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

	Years Ending December 31,
	2014		2013		2012
Major customers:
Phillips 66 (1)		12%		14%		12%
ConocoPhillips (1)	n/a		n/a			13%
Sinclair Oil & Gas Company		11%	n/a		n/a

(1) Phillips 66 purchased production pursuant to existing marketing agreements with terms that are currently on “evergreen” status. Evergreen contracts automatically renew on a month-to-month basis until either party gives 30 or 60 days advance written notice of non-renewal. Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012.  Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips.

General and Administrative Expense

We and our general partner have entered into an omnibus agreement with a wholly-owned subsidiary of Memorial Resource pursuant to which, among other things, Memorial Resource performs all operational, management and administrative services on our general partner’s and our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocated to us, including expenses incurred by our general partner and its affiliates on our behalf. Memorial Resource allocated indirect general and administrative costs based on time allocations for the year ended December 31, 2014, on production for the year ended December 31, 2013 and on a reserve basis methodology for the year ended December 31, 2012. Under our partnership agreement and the omnibus agreement, we reimburse Memorial Resource for all direct and indirect costs incurred on our behalf. See Note 12 for additional information regarding the omnibus agreement.

General and administrative expenses associated with the previous owners 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

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

variable rate borrowings under the credit facilities. Every derivative instrument is recorded on 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 as we have not elected hedge accounting for any of our derivative positions.

Capitalized Interest

We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method.  For the year ended December 31, 2014, we had $2.8 million in capitalized interest.  We did not have any capitalized interest for the years ended December 31, 2013 and 2012.

Income Tax

We are organized as a pass-through entity for federal and most state income tax purposes. As a result, our partners are responsible for federal and state income taxes on their share of our taxable income. Certain of our consolidated subsidiaries are taxed as corporations for federal and state income tax purposes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax.  The previous owners were organized as pass-through entities from inception through the date of the Memorial Resource initial public offering. Deferred income taxes arise due to temporary differences between the financial statement carrying value of existing assets and liabilities and their respective tax basis. A deferred tax liability was recorded in equity by the previous owners and related to Memorial Resource’s initial public offering and restructuring transactions as it represented a transaction among shareholders.  Subsequent to the Memorial Resource’s initial public offering, income tax related to the Property Swap were calculated on a separate return basis. See Note 15 for additional information.

We must recognize the income tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. If a tax position meets such criteria, the income tax effect that would be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized. There were no uncertain tax positions that required recognition in the financial statements at December 31, 2014 or 2013.  

Earnings Per Unit

Basic and diluted earnings per unit (“EPU”) is determined by dividing net income or loss available to the limited partners by the weighted average number of outstanding limited partner units during the period. Net income or loss available to the limited partners is determined by applying the two-class method. The two-class method of computing EPU is an earnings allocation formula that determines EPU based on distributions declared. The amount of net income or loss used in the determination of EPU is reduced (or increased) by the amount of available cash that has been or will be distributed to the limited partners for that corresponding period. The remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the limited partners in accordance with the contractual terms of the partnership agreement. The total earnings allocated to the limited partners is determined by adding together the amount allocated for distributions declared and the amount allocated for the undistributed earnings or excess distributions over earnings. Basic and diluted EPU are equivalent, as all restricted common units and subordinated units participate in distributions. See Note 10 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. We currently have no awards subject to performance criteria; however, such awards 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 11 for further information.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Incentive Units

The governing documents of certain entities within the Cinco Group and Classic provided for the issuance of incentive units. The incentive units were accounted for as liability awards with compensation expense based on period-end fair value. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. Tanos and Classic both recognized compensation expense related to the forfeiture of incentive units in 2013 as further discussed in Note 12.

Accounts Receivable – Joint Interest Owners and Other

Accounts receivable from joint interest owners and other consisted of the following at the dates indicated (in thousands):

	December 31,		December 31,
	2014		2013
Derivatives expired positions	$	13,754	$	—
Wyoming Acquisition		9,569		—
Joint interest owners		12,714		4,465
Other		900		645
	$	36,937	$	5,110

Accrued Liabilities

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

	December 31,		December 31,
	2014		2013
Accrued capital expenditures	$	36,042	$	22,283
Accrued interest payable		24,673		8,931
Accrued lease operating expense		15,594		11,002
Accrued ad valorem taxes		8,281		1,728
Accrued general and administrative expenses		1,276		1,583
Environmental liability		2,092		437
Other		3,016		878
	$	90,974	$	46,842

Supplemental Cash Flows

Supplemental cash flow for the periods presented (in thousands):

	For the Year Ended
	December 31,
	2014		2013		2012
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$	63,709	$	42,599	$	17,995
Cash paid for taxes		151		168		22
Noncash investing and financing activities:
Change in capital expenditures in payables and accrued liabilities		13,759		18,779		(19,719	)
Repurchases under unit repurchase program		1,372		—		—
Accounts receivable related to Wyoming Acquisition		9,569		—		—
Accounts receivable related to Double A Acquisition		586		—		—
Assumptions of asset retirement obligations related to properties acquired		4,265		1,581		5,448
Contribution related to sale of assets to NGP affiliate - restricted cash		—		—		2,013
Accrued distribution to NGP affiliates related to Cinco Group Acquisition		—		4,352		—
Accrued equity offering costs		—		—		170
Distributions to partners		—		—		48

New Accounting Pronouncements

Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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

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

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

Note 3. Acquisitions and Divestitures

The third party acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, we and the previous owners 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) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital.

The Partnership has consummated several common control acquisitions since completing its initial public offering in December 2011, as further discussed in Note 12, directly or indirectly from Memorial Resource and certain affiliates of NGP.

Acquisition-related costs

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

For the Year Ended
December 31,
2014		2013		2012
$	4,363	$	6,729	$	4,135

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

2014 Acquisitions

Wyoming Acquisition. On July 1, 2014, we consummated a transaction to acquire certain oil and natural gas liquids properties in Wyoming from a third party for an aggregate purchase price of approximately $906.1 million, including estimated post-closing adjustments (the “Wyoming Acquisition”). We recorded revenues of $72.0 million in the statement of operations and generated earnings of approximately $22.9 million related to the Wyoming Acquisition subsequent to the closing date. The following table summarizes the preliminary fair value of the third party assets acquired and liabilities assumed in the Wyoming Acquisition (in thousands):

	Wyoming
	Acquisition
Oil and gas properties	$	930,168
Asset retirement obligations		(3,980	)
Revenues payable		(375	)
Accrued liabilities		(19,693	)
Total identifiable net assets	$	906,120

Eagle Ford Acquisition. On March 25, 2014, we closed a transaction to acquire certain oil and natural gas producing properties in the Eagle Ford from a third party for approximately $168.1 million (the “Eagle Ford Acquisition”). In addition, we acquired a 30% interest in the seller’s Eagle Ford leasehold. During the year ended December 31, 2014, revenues of approximately $36.5 million were recorded in the statement of operations related to the Eagle Ford Acquisition subsequent to the closing date and we generated earnings of approximately $16.3 million for the year ended December 31, 2014.

The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands):

	Eagle Ford
	Acquisition
Oil and gas properties	$	168,606
Asset retirement obligations		(285	)
Accrued liabilities		(250	)
Total identifiable net assets	$	168,071

The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2014 and 2013 as though the Eagle Ford Acquisition and Wyoming Acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

	For the Year Ended December 31,
	2014 (1)		2013
	(In thousands, except per unit amounts)
Revenues	$	636,684	$	613,344
Net income (loss)		153,843		194,092
Basic and diluted earnings per unit		2.20		3.08

(1)      Amounts represent historical revenues and expenses from January 1, 2014 through the respective dates of acquisition.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

2013 Acquisitions

Third Party. We closed two separate transactions during the year ended December 31, 2013 to acquire certain oil and natural gas properties from third parties in East Texas (the “East Texas Acquisition”) and the Rockies (the “Rockies Acquisition”) for approximately $29.4 million in aggregate. The East Texas Acquisition closed on September 6, 2013 and the Rockies Acquisition closed on August 30, 2013. The following table summarizes the fair value of the third party assets acquired and liabilities assumed as of each acquisition date (in thousands):

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

The Cinco Group also acquired certain oil and gas properties and leases in Texas from third parties for a final purchase price of $9.3 million.

2012 Acquisitions

Third Party. 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 MRD LLC, the transaction was approved by the board of directors of our general partner (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. During the year ended December 31, 2012, approximately $4.8 million of revenue and $1.2 million of earnings were recorded in the statement of operations related to the Undisclosed Seller Acquisition subsequent to the closing date.

On September 28, 2012, we acquired certain oil and natural gas properties in East Texas from Goodrich Petroleum Corporation (“Goodrich Acquisition”), for a final net purchase price of $90.4 million after 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 East Henderson field of Rusk County, Texas. During the year ended December 31, 2012, approximately $4.6 million of revenue and $2.0 million of earnings were recorded in the statement of operations related to the Goodrich Acquisition subsequent to the closing date.

Collectively, the previous owners consummated multiple acquisitions during 2012 by acquiring operating and non-operating interests in certain oil and natural gas properties primarily located in various Texas and New Mexico counties for an aggregate adjusted purchase price of $150.7 million, the largest of which was completed in July by Stanolind. In July 2012, Stanolind completed an acquisition of working interests, royalty interests and net revenue interests (the “Menemsha Acquisition”) located in various counties in Texas for a final purchase price of $74.7 million. During the year ended December 31, 2012, approximately $4.9 million of revenue and $0.9 million of earnings were recorded in the statements of operations related to the Menemsha Acquisition subsequent to the closing date.

The following table summarizes the fair value of the third party assets acquired and liabilities assumed as of each acquisition date (in thousands).

	Undisclosed Seller			Goodrich			Menemsha			Other
	Acquisition			Acquisition			Acquisition			Acquisitions
Oil and gas properties	$	36,865		$	91,187		$	75,114		$	80,591
Prepaid expenses and other current assets		—			425			—			—
Revenues payable		—			(875	)		—			—
Asset retirement obligations		(321	)		(161	)		(408	)		(4,558	)
Accrued liabilities		(83	)		(153	)		—			—
Total identifiable net  assets	$	36,461		$	90,423		$	74,706		$	76,033

The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2012 as though the Undisclosed Seller Acquisition, Goodrich Acquisition, and Menemsha Acquisition had been completed on January 1, 2011.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transactions occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

	For the Year
	Ended December 31,
	2012
	(In thousands, except per unit amounts)
Revenues	$	320,746
Net income		35,021
Basic and diluted earnings per unit		0.53

Previous Owners’ Divestitures

On January 1, 2013, Tanos sold a natural gas gathering pipeline located in East Texas, which it had originally acquired in April 2010, to a privately held gas transportation company for a minimum of $1.5 million. The maximum allowable additional proceeds are $2.0 million. The contingent consideration is based on the natural gas pipeline servicing any new wells that Tanos drills in the area over the following three years. The contingent consideration portion of an arrangement is recorded when the consideration is determined to be realizable. Tanos recorded an aggregate gain of approximately $1.4 million related to this transaction, of which $0.4 million was contingent consideration. Tanos also sold certain non-operated oil and gas properties in 2013 for $2.9 million and recorded a gain of $1.4 million.

The previous owners sold certain interests in oil and gas properties located offshore Louisiana on October 11, 2012 for an aggregate $40.1 million to an NGP controlled entity, of which $38.1 million was received upon closing and the remaining proceeds were released from escrow in April 2013. Due to common control considerations, the proceeds from the sale exceeded the net book value of the properties sold by $6.3 million and is recognized in the equity statement as a net contribution.

On July 11, 2012, the Cinco Group completed the sale of a portion of its oil and gas assets located in Garza County, Texas to a third party for $26.1 million and recognized a gain of approximately $7.6 million. On September 18, 2012, the Cinco Group completed the sale of a portion of its oil and gas assets located in Ector County, Texas to a third party for $4.7 million and recognized a gain of approximately $2.2 million.

The majority of the proceeds generated from these sales were used to acquire operating and non-operating interests in certain oil and natural gas properties located primarily in various Texas and New Mexico counties.

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. At December 31, 2014 and 2013, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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 with variable rates included in the accompanying balance sheets approximated fair value at December 31, 2014 and December 31, 2013. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 8 for the estimated fair value of our outstanding fixed-rate debt.

The fair market values of the derivative financial instruments reflected on the balance sheets as of December 31, 2014 and December 31, 2013 were based on estimated forward commodity prices (including nonperformance risk) and forward interest rate yield curves. Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled.  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, 2014 and December 31, 2013 for each of the fair value hierarchy levels:

	Fair Value Measurements at December 31, 2014 Using
	Quoted Prices in		Significant Other		Significant
	Active Market		Observable Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	564,913	$	—	$	564,913
Interest rate derivatives		—		1,305		—		1,305
Total assets	$	—	$	566,218	$	—	$	566,218
Liabilities:
Commodity derivatives	$	—	$	45,831	$	—	$	45,831
Interest rate derivatives		—		3,289		—		3,289
Total liabilities	$	—	$	49,120	$	—	$	49,120

	Fair Value Measurements at December 31, 2013 Using
	Quoted Prices in		Significant Other		Significant
	Active Market		Observable Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	95,926	$	—	$	95,926
Interest rate derivatives		—		872		—		872
Total assets		—		96,798		—		96,798
Liabilities:
Commodity derivatives	$	—	$	55,576	$	—	$	55,576
Interest rate derivatives		—		4,836		—		4,836
Total liabilities	$	—	$	60,412	$	—	$	60,412

See Note 5 for additional information regarding our derivative instruments.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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; and inflation rates. See Note 6 for a summary of changes in AROs.

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

· Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. 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.

· During the year ended December 31, 2014, we recognized $407.5 million of impairments. The impairments primarily related to certain properties located in the Permian Basin, East Texas, and South Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable.  In the Permian Basin, the impairments were in due to a downward revision of estimated proved reserves based on declining commodity prices and updated well performance data.  In South Texas, the impairments were due to a downward revision of estimated proved reserves based on declining commodity prices and increased operating costs. In East Texas, the impairments were due to downward revisions based on declining commodity prices. The carrying value of the: (i) Permian Basin properties after the $234.2 million impairment was approximately $88.7 million; (ii) East Texas properties after the $107.6 million impairment was approximately $88.8 million; and (iii) South Texas properties after the $65.6 million impairment was $71.2 million. 

· During the year ended December 31, 2013, we recognized $4.1 million of impairments. The impairments related to certain properties located in South Texas.  The estimated future cash flows expected from South Texas properties were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on pricing terms specific to these properties. The carrying value of these properties after the $4.1 million impairment was approximately $7.3 million.

· During the year ended December 31, 2012, the previous owners recognized $23.0 million of impairments to proved oil and natural gas properties. Approximately $8.0 million related to a particular lease in the Elkhorn (Ellenburger) and Canyon Fields located in the Permian Basin as a result of a downward revision of estimated proved reserves due to unfavorable drilling results in the area.  Impairments for the year ended December 31, 2012 also include approximately $12.5 million in impairments recorded by the previous owners related to certain properties located in East Texas as a result of downward revisions due to declines in natural gas prices.

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 creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreement are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. As a result, had certain counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $207.3 million against amounts outstanding under our revolving credit facility at December 31, 2014, reducing our maximum credit exposure to approximately $309.8 million, of which approximately $109.7 million was with a single counterparty. See Note 8 for additional information regarding our revolving credit facility.

Commodity Derivatives

A combination of commodity derivatives (e.g., floating-for-fixed swaps, costless collars, call spreads and basis swaps) is used to manage exposure to commodity price volatility. Historically, the Partnership has not paid or received premiums for put options. We enter into natural gas derivative contracts that are indexed to NYMEX Henry Hub and regional indices such as NGPL TXOK, TETCO STX, and Houston Ship Channel in proximity to the Partnership’s areas of production. We also enter into oil derivative contracts indexed to a variety of locations such as NYMEX WTI, Inter-Continental Exchange (“ICE”) Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu. At December 31, 2014, the Partnership had the following open commodity positions:

	2015			2016			2017		2018		2019
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		2,605,278			2,692,442			2,450,067		2,160,000		1,914,583
Weighted-average fixed price	$	4.28		$	4.40		$	4.31	$	4.51	$	4.75
Collar contracts:
Average Monthly Volume (MMBtu)		350,000			—			—		—		—
Weighted-average floor price	$	4.62		$	—		$	—	$	—	$	—
Weighted-average ceiling price	$	5.80		$	—		$	—	$	—	$	—
Call spreads (1):
Average Monthly Volume (MMBtu)		80,000			—			—		—		—
Weighted-average sold strike price	$	5.25		$	—		$	—	$	—	$	—
Weighted-average bought strike price	$	6.75		$	—		$	—	$	—	$	—
Basis swaps:
Average Monthly Volume (MMBtu)		2,940,000			2,508,333			415,000		115,000		—
Spread	$	(0.12	)	$	(0.04	)	$	0.00	$	0.15	$	—
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		314,281			332,813			326,600		312,000		160,000
Weighted-average fixed price	$	90.96		$	85.83		$	84.38	$	83.74	$	85.52
Collar contracts:
Average Monthly Volume (Bbls)		5,000			—			—		—		—
Weighted-average floor price	$	80.00		$	—		$	—	$	—	$	—
Weighted-average ceiling price	$	94.00		$	—		$	—	$	—	$	—
Basis swaps:
Average Monthly Volume (Bbls)		97,500			95,000			—		—		—
Spread	$	(7.07	)	$	(9.56	)	$	—	$	—	$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		149,200			84,600			—		—		—
Weighted-average fixed price	$	43.02		$	41.49		$	—	$	—	$	—

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

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Our basis swaps included in the table above are presented on a disaggregated basis below:

	2015			2016			2017			2018
Natural Gas Derivative Contracts:
NGPL TexOk basis swaps:
Average Monthly Volume (MMBtu)		2,280,000			2,103,333			300,000			—
Spread	$	(0.11	)	$	(0.06	)	$	(0.05	)	$	—
HSC basis swaps:
Average Monthly Volume (MMBtu)		150,000			135,000			115,000			115,000
Spread	$	(0.08	)	$	0.07		$	0.14		$	0.15
CIG basis swaps:
Average Monthly Volume (MMBtu)		210,000			—			—			—
Spread	$	(0.25	)	$	—		$	—		$	—
TETCO STX basis swaps:
Average Monthly Volume (MMBtu)		300,000			270,000			—			—
Spread	$	(0.09	)	$	0.06		$	—		$	—
Crude Oil Derivative Contracts:
Midway-Sunset basis swaps:
Average Monthly Volume (Bbls)		57,500			55,000			—			—
Spread - Brent	$	(9.73	)	$	(13.35	)	$	—		$	—
Midland basis swaps:
Average Monthly Volume (Bbls)		40,000			40,000			—			—
Spread - WTI	$	(3.25	)	$	(4.34	)	$	—		$	—

Interest Rate Swaps

Periodically, interest rate swaps are entered into to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. At December 31, 2014, we had the following interest rate swap open positions:

	2015			2016			2017
Average Monthly Notional (in thousands)	$	314,167		$	250,000		$	250,000
Weighted-average fixed rate		1.349	%		1.029	%		1.620	%
Floating rate	1 Month LIBOR			1 Month LIBOR			1 Month LIBOR

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Balance Sheet Presentation

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

		Asset Derivatives						Liability Derivatives
		December 31,			December 31,			December 31,			December 31,
Type	Balance Sheet Location	2014			2013			2014			2013
		(In thousands)
Commodity contracts	Short-term derivative instruments	$	225,882		$	18,578		$	17,297		$	17,120
Interest rate swaps	Short-term derivative instruments		—			845			3,289			2,699
Gross fair value			225,882			19,423			20,586			19,819
Netting arrangements	Short-term derivative instruments		(17,297	)		(11,823	)		(17,297	)		(11,823	)
Net recorded fair value	Short-term derivative instruments	$	208,585		$	7,600		$	3,289		$	7,996
Commodity contracts	Long-term derivative instruments	$	339,031		$	77,348		$	28,534		$	38,456
Interest rate swaps	Long-term derivative instruments		1,305			27			—			2,137
Gross fair value			340,336			77,375			28,534			40,593
Netting arrangements	Long-term derivative instruments		(28,534	)		(34,718	)		(28,534	)		(34,718	)
Net recorded fair value	Long-term derivative instruments	$	311,802		$	42,657		$	—		$	5,875

(Gains) Losses on Derivatives

We do not designate derivative instruments as hedging instruments for accounting and financial reporting purposes and neither did the previous owners. Accordingly, all gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations. The following table details the gains and losses related to derivative instruments for the years ending December 31, 2014, 2013, and 2012 (in thousands):

	Statements of	For the Year Ended December 31,
	Operations Location	2014			2013			2012
Commodity derivative contracts	(Gain) loss on commodity derivatives	$	(492,254	)	$	(26,133	)	$	(24,405	)
Interest rate derivatives	Interest expense, net		(151	)		(548	)		4,839

Note 6. Asset Retirement Obligations

The Partnership’s asset retirement obligations primarily relate to the Partnership’s portion of future plugging and abandonment of wells and related facilities. The following table presents the changes in the asset retirement obligations for the years ended December 31, 2014, 2013, and 2012:

	2014			2013			2012
	(in thousands)
Asset retirement obligations at beginning of period	$	101,436		$	93,031		$	83,696
Liabilities added from acquisitions or drilling		5,815			2,116			5,967
Liabilities removed upon sale of wells		—			—			(1,795	)
Liabilities settled		(651	)		(20	)		(91	)
Accretion expense		5,773			4,988			4,458
Revision of estimates		329			1,321			796
Asset retirement obligations at end of period	$	112,702		$	101,436		$	93,031

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 7. Restricted Investments

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. The components of the restricted investment balance are as follows:

	December 31,		December 31,
	2014		2013
	(In thousands)
BOEM platform abandonment (See Note 13)	$	69,954	$	66,373
BOEM lease bonds		794		794
SPBPC Collateral:
Contractual pipeline and surface facilities abandonment		2,701		2,306
California State Lands Commission pipeline right-of-way bond		3,005		3,005
City of Long Beach pipeline facility permit		500		500
Federal pipeline right-of-way bond		307		307
Port of Long Beach pipeline license		100		100
Restricted investments	$	77,361	$	73,385

Note 8. Long Term Debt

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

	December 31,			December 31,
	2014			2013
	(In thousands)
MEMP:
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018	$	412,000		$	103,000
2021 Senior Notes, fixed-rate, due May 2021 (1)		700,000			700,000
2022 Senior Notes, fixed-rate, due August 2022 (2)		500,000			—
Unamortized discounts		(16,587	)		(10,933	)
Total long-term debt	$	1,595,413		$	792,067

(1)      The estimated fair value of our 2021 Senior Notes was $563.5 million and $721.0 million at December 31, 2014 and 2013, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

(2)      The estimated fair value of our 2022 Senior Notes was $380.0 million at December 31, 2014.  The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

Subsidiary Guarantors

We are a “Well-Known Seasoned Issuer” under SEC rules and have filed a universal shelf registration statement with the SEC that allows us to issue debt and equity securities.  Any debt securities issued will be governed by an indenture. Our outstanding debt securities are, and any debt securities issued in the future will likely be, jointly and severally, fully and unconditionally guaranteed (subject to customary release provisions) by certain of the Partnership’s subsidiaries (collectively, the “Guarantor Subsidiaries”). The Guarantor Subsidiaries are 100% owned by the Partnership. The Partnership has no material assets or operations independent of the Guarantor Subsidiaries and there are no significant restrictions upon the ability of the Guarantor Subsidiaries to distribute funds to the Partnership.

Borrowing Base

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

	December 31,
	2014
	(In thousands)
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018	$	1,440,000

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

OLLC Revolving Credit Facility

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

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.

Borrowings under our revolving credit facility bear interest, at our option, at either: (i) the Alternate Base Rate defined as 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 0.50% to 1.50% 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), (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage, or (iii) the applicable LIBOR Market Index Rate plus a margin that varies from 1.50% to 2.50% 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.

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.

During the year ended December 31, 2014, the revolving credit facility was primarily used to fund the acquisitions of oil and gas properties. See Note 3 for additional information regarding these acquisitions.

2022 Senior Notes  

On July 17, 2014, we and Finance Corp. (collectively, the “Issuers”) completed a private placement of $500.0 million aggregate principal amount of 6.875% senior unsecured notes due 2022 (the “2022 Senior Notes”). The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by the Guarantor Subsidiaries and by certain future subsidiaries of the Partnership. The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year, commencing February 1, 2015.

The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2022 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the Issuers, all outstanding 2022 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2022 Senior Notes may declare all the 2022 Senior Notes to be due and payable immediately.

F- 24

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

2021 Senior Notes

On April 17, 2013, May 23, 2013 and October 10, 2013, the Issuers issued $300.0 million, $100.0 million and $300.0 million, respectively, of 7.625% senior unsecured notes due 2021 (the “2021 Senior Notes”). The 2021 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by the Guarantor Subsidiaries and by certain future subsidiaries of the Partnership. The 2021 Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes are governed by an indenture and are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The Issuers may also be required to repurchase the 2021 Senior Notes upon a change of control.  

The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2021 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the Issuers or any subsidiary guarantor that is a significant subsidiary, all outstanding 2021 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2021 Senior Notes may declare all the 2021 Senior Notes to be due and payable immediately.

Previous Owner Revolving Credit Facilities

REO, WHT, Stanolind, Boaz, Crown, Tanos, Propel and Classic each maintained multi-year variable-rate senior secured revolving credit facilities that were primarily used for both working capital needs and to fund acquisition and development expenditures. All of Stanolind’s indebtedness outstanding under the Stanolind revolving credit facility was attributable to Stanolind SPV. Likewise, all of Propel Energy’s indebtedness outstanding under the Propel Energy revolving credit facility was attributable to Propel SPV.

On December 12, 2012, indebtedness then outstanding under the REO’s revolving credit facility of $28.5 million and all accrued interest was paid off in full and the revolving credit facility was terminated. On November 20, 2012, indebtedness then outstanding under the Classic revolving credit facility of $80.0 million and all accrued interest was paid off in full with borrowings under the MRD LLC revolving credit facility and the Classic revolving credit facility was terminated. On March 28, 2013, the debt balance then outstanding under the WHT revolving credit facility of $89.3 million and all accrued interest was paid off in full and the revolving credit facility was terminated. On April 1, 2013, indebtedness then outstanding under the Tanos revolving credit facility of $27.0 million was repaid and on April 25, 2013 all accrued interest was paid off in full and the revolving credit facility was terminated. On October 1, 2013, the debt balance then outstanding under the Boaz and Crown revolving credit facilities and all accrued interest was paid off in full and these revolving credit facilities were terminated. On October 1, 2013, the debt balance then outstanding under the Stanolind and Propel Energy revolving credit facilities and all accrued interest was paid off in full by the Partnership on behalf of Stanolind and Propel Energy, respectively.

All of the indebtedness outstanding under the MRD LLC revolving credit facility was attributable to Classic.  On November 22, 2013, the borrowing base under this revolving credit facility was automatically reduced and triggered a mandatory principal repayment of $20.0 million.  This principal repayment is reflected in previous owner equity as a contribution.  On December 18, 2013, indebtedness then outstanding under the MRD LLC revolving credit facility of $59.7 million and all accrued interest was paid off in full and the revolving credit facility was terminated. This principal repayment is also reflected in previous owner equity as a contribution.

F- 25

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Joint and Several Liability Arrangements

Classic jointly and severally, as well as fully and unconditionally, guaranteed the following debt arrangements of its parent, Memorial Resource:

· On December 18, 2013, MRD LLC and its wholly-owned subsidiary, Memorial Resource Finance Corp. (“MRD Finance Corp.” and collectively, the “MRD Issuers”), completed a private placement of $350.0 million in aggregate principal amount of 10.00% / 10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”).  In connection with the closing of Memorial Resource’s initial public offering, Memorial Resource assumed the obligations of MRD LLC under the PIK notes indenture and the related debt security agreement. A redemption notice was delivered to the PIK notes trustee on June 16, 2014, which specified a redemption date of July 16, 2014.  On June 27, 2014, Memorial Resource irrevocably deposited with the PIK notes trustee an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge its obligations under the PIK notes and the related indenture. The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee.

· On June 18, 2014, Memorial Resource, as borrower, and certain of its subsidiaries, as guarantors, entered into a revolving credit facility, which is a five-year, $2.0 billion revolving credit facility with an initial borrowing base of $725.0 million and aggregate elected commitments of $725.0 million.  Indebtedness outstanding under this revolving credit facility was $183.0 million at December 31, 2014.

· On July 10, 2014, MRD completed a private placement of $600.0 million aggregate principal amount of 5.875% senior unsecured notes due 2022.

No amounts were recognized by Classic related to any of these debt arrangements.  On February 23, 2015, Classic was released from all joint and several obligations.

Weighted-Average Interest Rates

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

	For the Year Ended December 31,
	2014			2013			2012
OLLC revolving credit facility		2.67	%		3.25	%		2.74	%
Classic revolving credit facility	n/a			n/a				4.50	%
MRD LLC revolving credit facility	n/a				3.17	%		4.11	%
WHT revolving credit facility	n/a				2.29	%		2.60	%
REO revolving credit facility	n/a			n/a				3.40	%
Stanolind revolving credit facility	n/a				3.52	%		3.76	%
Boaz revolving credit facility	n/a				2.97	%		3.12	%
Crown revolving credit facility	n/a				3.38	%		4.20	%
Tanos revolving credit facility	n/a				3.10	%		2.31	%
Propel Energy revolving credit facility	n/a				3.08	%		3.28	%

Unamortized Deferred Financing Costs

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

	December 31,		December 31,
	2014		2013
	(In thousands)
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1)	$	6,468	$	5,413
2021 Senior Notes (2)		13,308		15,053
2022 Senior Notes (2)		7,958		—
Total	$	27,734	$	20,466

(1)      Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility.

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

F- 26

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Advances and Repayments

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

				Previous Owner
	OLLC Revolving			Revolving
	Credit Facility			Credit Facility			Total
For the Twelve Months Ended December 31, 2014:
Advances on revolving credit facility	$	1,446,000		$	—		$	1,446,000
Payments on revolving credit facility		(1,137,000	)		—			(1,137,000	)
For the Twelve Months Ended December 31, 2013:
Advances on revolving credit facility	$	941,000		$	17,355		$	958,355
Payments on revolving credit facility		(1,209,000	)		(356,537	)		(1,565,537	)
For the Twelve Months Ended December 31, 2012:
Advances on revolving credit facility	$	293,000		$	203,500		$	496,500
Payments on revolving credit facility		(42,000	)		(184,819	)		(226,819	)

For accounting and financial reporting purposes, any amounts that were repaid concurrent with the closing of the Beta acquisition, the WHT Properties, or the Cinco Group acquisition were a component of the net assets that were acquired by us and reflected on our supplemental consolidated and combined cash flow statement as “Payments on revolving credit facilities.”

Letters of credit

At December 31, 2014, we had $6.7 million of letters of credit outstanding related to operations at our properties acquired in the Wyoming Acquisition.

Note 9. Equity and Distributions

2014 Public Equity Offerings

On September 9, 2014, we issued 14,950,000 common units representing limited partner interests in the Partnership (including 1,950,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $22.29 per unit generating total net proceeds of approximately $321.3 million after deducting underwriting discounts and offering expenses. The net proceeds from the equity offering, including our general partner’s proportionate capital contribution, were used to repay a portion of the outstanding borrowings under our revolving credit facility.

On July 15, 2014, we issued 9,890,000 common units representing limited partner interests in the Partnership (including 1,290,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the underwriters at a negotiated price of $22.25 per unit generating total net proceeds of approximately $220.0 million after deducting offering expenses. The net proceeds from the equity offering, including our general partner’s proportionate capital contribution, were used to repay a portion of the outstanding borrowings under our revolving credit facility.

2013 Public Equity Offerings

On March 25, 2013, we issued 9,775,000 common units representing limited partner interests in the Partnership (including 1,275,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $18.35 per unit generating total net proceeds of approximately $171.8 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering, including our general partner’s proportionate capital contribution, partially funded the acquisition of all of the outstanding equity interests in WHT as further discussed under Note 12.

On October 8, 2013, we issued 16,675,000 common units representing limited partner interests in the Partnership (including 2,175,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $19.90 per unit generating total net proceeds of approximately $318.3 million after deducting

F- 27

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

underwriting discounts and offering expenses. The net proceeds from this equity offering, including our general partner’s proportional capital contribution, were used to repay a portion of outstanding borrowings under our revolving credit facility.

2012 Public Equity Offering

On December 12, 2012, we issued 10,500,000 common units representing limited partner interests in the Partnership to the public at an offering price of $17.00 per unit generating total net proceeds of $170.0 million after deducting underwriting discounts and offering expenses. Concurrent with the closing of this equity offering, the Partnership distributed cash to Rise and repaid all amounts outstanding under REO’s credit facility as consideration for the Beta acquisition as further discussed under Notes 8 and 12. The net proceeds from this equity offering, including our general partner’s proportionate capital contribution, partially funded the Beta acquisition.

On December 21, 2012, the underwriters purchased an additional 1,475,000 common units pursuant to their over-allotment option. We used the net proceeds of approximately $24.1 million from the sale of the additional common units, including our general partner’s proportionate capital contribution, to repay indebtedness under our revolving credit facility.

Equity Outstanding

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

						General
	Common			Subordinated		Partner
Balance, December 31, 2011		16,661,294			5,360,912		22,044
Common units issued		11,975,000			—		—
Restricted common units issued		287,943			—		—
Restricted common units forfeited		(2,334	)		—		—
General partner units issued		—			—		12,273
Balance, December 31, 2012		28,921,903			5,360,912		34,317
Common units issued		26,450,000			—		—
Restricted common units issued		524,717			—		—
Restricted common units forfeited		(11,734	)		—		—
Restricted common units repurchased (1)		(7,055	)		—		—
General partner units issued		—			—		26,983
Balance, December 31, 2013		55,877,831			5,360,912		61,300
Common units issued		24,840,000			—		—
Restricted common units issued		684,954			—		—
Restricted common units forfeited		(38,294	)		—		—
Restricted common units repurchased (1)		(42,587	)		—		—
Common units repurchased under repurchase program		(899,912	)		—		—
General partner units issued		—			—		25,497
Balance, December 31, 2014		80,421,992			5,360,912		86,797

(1) Restricted common units are generally net-settled by unitholders to cover the required withholding tax upon vesting. Unitholders surrendered units with value equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were $1.0 million and $0.1 million for the years ended December 31, 2014 and 2013, respectively. These net-settlements had the effect of unit repurchases by the Partnership as they reduced the number of units that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Partnership.

Restricted common units are a component of common units as presented on our supplemental consolidated and combined balance sheets. See Note 11 for additional information regarding restricted common units that were granted during the years ended December 31, 2014, 2013 and 2012.

As of December 31, 2014, MRD Holdco owned 100% of the subordinated units. Memorial Resource owns 100% of our general partner, which owns 50% of our incentive distribution rights. The Funds collectively indirectly own 50% of our incentive distribution rights.

Common & Subordinated Units. The common units and the subordinated units are separate classes of the 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. The subordination period ended on February 13, 2015.

F- 28

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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 and IDRs. Our general partner owns a 0.1% interest in us. 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, general partner and holders of our IDRs will receive. The general partner has the management rights as set forth in our partnership agreement.

Allocations of Net Income (Loss)

Net income (loss) attributable to the Partnership is allocated between our general partner and the common and subordinated unitholders in proportion to their pro rata ownership after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated to our general partner and NGP. Net income (loss) attributable to acquisitions accounted for as a transaction between entities under common control prior to their acquisition date is allocated to the previous owners.

Cash 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. We have also issued IDRs, which entitle the holder(s) thereof to additional increasing percentages, up to a maximum of 24.9%, of the cash we distribute in excess of $0.54625 per common unit per quarter. Our general partner owns 50%, and the Funds indirectly own 50%, of the IDRs.

Minimum Quarterly Distribution. During the subordination period, the common units had 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 were deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units were not entitled to receive any distributions from operating surplus until the common units had received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages were paid on the subordinated units. The practical effect of the subordinated units was to increase the likelihood that during the subordination period there would be available cash from operating surplus to be distributed on the common units.  The subordination period ended on February 13, 2015.

F- 29

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Our partnership agreement required 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 distributed 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 distributed 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 distributed 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 was distributed to the unitholders and the general partner based on the percentages in the table below.

The holders of the IDRs are entitled to incentive distributions if the amount we distribute with respect to one quarter exceeds specified target levels shown below:

	Target Quarterly Distributions		Marginal Percentage Interest in Distributions
	Target Amount		Unitholders			General Partner			IDR (1)
Minimum Quarterly Distribution	$	0.4750		99.9	%		0.1	%		—
First Target Distribution	above $0.4750 up to $0.54625			99.9	%		0.1	%		—
Second Target Distribution	above $0.54625 up to $0.59375			85.0	%		0.1	%		14.9	%
Thereafter	above $0.59375			75.0	%		0.1	%		24.9	%

(1)      The Funds collectively indirectly own 50% of our incentive distribution rights.  The remaining IDRs are owned by our general partner.

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period (i.e., the first quarter of 2015) 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, the general partner and the holders of the IDRs based on the percentages in the table above.

The subordination period extended 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 were 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;

· 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.

On February 13, 2015, each outstanding subordinated unit converted into one common unit and will 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, 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

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

F- 30

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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

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

								Distribution
				Amount		Aggregate		Received by
Quarter	Declaration Date	Record Date	Payable Date	Per Unit		Distribution		Affiliates
4th Quarter 2014	January 26, 2015	February 5, 2015	February 12, 2015	$	0.5500	$	46.3	$	3.1
3rd Quarter 2014	October 23, 2014	November 5, 2014	November 12, 2014	$	0.5500	$	47.8	$	3.1
2nd Quarter 2014	July 24, 2014	August 5, 2014	August 12, 2014	$	0.5500	$	39.5	$	3.0
1st Quarter 2014	April 24, 2014	May 6, 2014	May 13, 2014	$	0.5500	$	33.8	$	3.0
4th Quarter 2013	January 27, 2014	February 6, 2014	February 13, 2014	$	0.5500	$	33.8	$	3.0
3rd Quarter 2013	October 22, 2013	November 1, 2013	November 12, 2013	$	0.5500	$	33.8	$	6.9
2nd Quarter 2013	July 18, 2013	August 1, 2013	August 12, 2013	$	0.5125	$	22.9	$	6.4
1st Quarter 2013	April 18, 2013	May 1, 2013	May 13, 2013	$	0.5125	$	22.6	$	6.4
4th Quarter 2012	January 15, 2013	February 1, 2013	February 13, 2013	$	0.5075	$	17.4	$	6.3
3rd Quarter 2012	October 19, 2012	November 1, 2012	November 12, 2012	$	0.4950	$	11.1	$	6.2
2nd Quarter 2012	July 19, 2012	August 1, 2012	August 13, 2012	$	0.4800	$	10.7	$	6.0
1st Quarter 2012	April 19, 2012	May 1, 2012	May 14, 2012	$	0.4800	$	10.7	$	6.0

Previous Owners Capital

The following table summarizes our previous owners’ equity transactions with respect to the period indicated (dollars in thousands):

	Tanos/Classic Properties			REO			WHT Properties			Cinco Group			Property Swap			Total Previous Owners
Balance, December 31, 2011	$	50,853		$	72,755		$	99,524		$	211,444		$	148,582		$	583,158
Net income		1,000			28,691			8,369			8,233			(23,451	)		22,842
Contributions		—			—			—			64,597			—			64,597
Contribution of oil and gas properties		—			—			—			6,893			—			6,893
Distribution attributable to net assets acquired		—			—			—			—			27,000			27,000
Net book value of net assets acquired by Partnership		(50,639	)		(93,696	)		—			—			—			(144,335	)
Contribution related to sale of assets to NGP affiliate		—			—			—			40,138			—			40,138
Net book value of net assets acquired by NGP affiliate		—			—			—			(33,859	)		—			(33,859	)
Distributions		(1,214	)		(7,750	)		—			(20,553	)		1,079			(28,438	)
Other		—			—			—			(92	)		(112	)		(204	)
Balance, December 31, 2012		—			—			107,893			276,801			153,098			537,792
Net income (loss)		—			—			(1,219	)		12,494			40,737			52,012
Contributions		—			—			—			7,233			89,570			96,803
Distribution attributable to net assets acquired		—			—			—			55,281			—			55,281
Net book value of net assets acquired by Partnership		—			—			(106,674	)		(297,627	)		—			(404,301	)
Distributions		—			—			—			(31,098	)		—			(31,098	)
Other		—			—			—			(2,302	)		—			(2,302	)
Net assets retained by previous owners		—			—			—			(20,782	)		—			(20,782	)
Balance, December 31, 2013	$	—		$	—		$	—		$	—		$	283,405		$	283,405
Net income (loss)		—			—			—			—			(2,465	)		(2,465	)
Contributions		—			—			—			—			5,990			5,990
Distributions		—			—			—			—			(9,886	)		(9,886	)
Distribution of net asset to MRD Holdco		—			—			—			—			(26,131	)		(26,131	)
Tax related effects attributable to Memorial Resource restructuring transactions and initial public offering		—			—			—			—			(30,483	)		(30,483	)
Other		—			—			—			—			227			227
Balance, December 31, 2014	$	—		$	—		$	—		$	—		$	220,657		$	220,657

F- 31

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 10. Earnings per Unit

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

	For the Year Ended
	December 31,
	2014			2013		2012
Net income (loss) attributable to Memorial Production Partners LP	$	115,582		$	60,738	$	22,963
Less: Previous owners interest in net income (loss)		(2,465	)		52,012		22,842
Less: General partner's 0.1% interest in net income (loss)		118			9		—
Less: IDRs attributable to corresponding period		202			81		—
Net income (loss) available to limited partners	$	117,727		$	8,636	$	121
Weighted average limited partner units outstanding:
Common units		65,498			40,656		17,519
Subordinated units		5,361			5,361		5,361
Total		70,859			46,017		22,880
Basic and diluted EPU	$	1.66		$	0.19	$	0.01

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

	For the Year Ended
	December 31,
	2014		2013		2012
Net income (loss) attributable to Memorial Production Partners LP	$	115,582	$	60,738	$	22,963
Less: General partner's 0.1% interest in net income (loss)		116		61		23
Less: IDRs attributable to corresponding period		202		81		—
Net income (loss) available to limited partners	$	115,264	$	60,596	$	22,940
Weighted average limited partner units outstanding:
Common units		65,498		40,656		17,519
Subordinated units		5,361		5,361		5,361
Total		70,859		46,017		22,880
Supplemental basic and diluted EPU	$	1.63	$	1.32	$	1.00

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

Note 11. Equity-based Awards

Long-Term Incentive Plan

In December 2011, the Board adopted the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) for employees, officers, consultants and directors of the general partner and any of its affiliates, including Memorial Resource, who perform services for the Partnership. The LTIP consists of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The LTIP initially limits the number of common units that may be delivered pursuant to awards under the plan to 2,142,221 common units. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The LTIP is administered by the Board or a committee thereof. During the years ended December 31, 2014, 2013 and 2012 there were multiple awards of restricted common units that were granted under the LTIP to both executive officers and independent directors of our general partners and other Memorial Resource employees.

The restricted common units awarded are subject to restrictions on transferability, customary forfeiture provisions and typically graded vesting provisions in which one-third of each award vests on the first, second, and third anniversaries of the date of grant.

F- 32

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

Based on the market price per unit on the date of grant, the aggregate fair value of the restricted common units awarded to our general partner’s executive officers and other Memorial Resource employees during the years ended December 31, 2014, 2013 and 2012 was $15.0 million, $9.7 million and $5.0 million, respectively. The restricted common units granted are accounted for as equity-classified awards. The grant-date fair value net of estimated forfeitures is recognized as compensation cost on a straight-line basis over the requisite service period. The fair value of the restricted unit awards granted to the independent directors of our general partner are also recognized as compensation cost on a straight-line basis over the requisite service period. Compensation costs are recorded as direct general and administrative expenses.

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

				Weighted-
				Average Grant
				Date Fair Value
	Number of Units			per Unit (1)
Restricted common units outstanding at December 31, 2011		—		$	—
Granted (2)		287,943		$	18.07
Forfeited		(2,334	)	$	17.14
Restricted common units outstanding at December 31, 2012		285,609		$	18.08
Granted (3)		524,718		$	18.83
Forfeited		(11,734	)	$	17.24
Vested		(91,666	)	$	18.31
Restricted common units outstanding at December 31, 2013		706,927		$	18.62
Granted (4)		684,954		$	22.39
Forfeited		(38,294	)	$	20.54
Vested		(260,067	)	$	18.56
Restricted common units outstanding at December 31, 2014		1,093,520		$	20.93

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

(2)      The aggregate grant date fair value of restricted common unit awards issued in 2012 was $5.2 million based on grant date market prices ranging from of $17.14 to $18.58 per unit.

(3)      The aggregate grant date fair value of restricted common unit awards issued in 2013 was $9.9 million based on grant date market prices ranging from of $18.33 to $20.35 per unit.

(4)      The aggregate grant date fair value of restricted common unit awards issued in 2014 was $15.3 million based on grant date market prices ranging from of $21.99 to $23.40 per unit.

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

For the Year Ended December 31,
2014		2013		2012
$	7,874	$	3,558	$	1,423

The unrecognized compensation cost associated with restricted common unit awards was an aggregate $16.5 million at December 31, 2014. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.1 years.

Since the restricted common units are participating securities, any distributions received by the restricted common unitholders are included in distributions to partners as presented on our statements of supplemental consolidated and combined cash flows. During the years ended December 31, 2014, 2013 and 2012, the restricted common unitholders received a distribution of approximately $1.9 million, $1.0 million and $0.2 million, respectively.

Note 12. Related Party Transactions

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

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Common Control Acquisitions

2014 Acquisitions

On April 1, 2014, we acquired certain oil and natural gas properties in East Texas from a subsidiary of MRD LLC, for approximately $33.3 million, including customary post-closing adjustments (the “Double A Acquisition”). The acquired properties primarily represent additional working interests in wells currently owned by us and located in Polk and Tyler Counties in the Double A Field of East Texas as well as the Sunflower, Segno and Sugar Creek Fields. Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee, which is comprised entirely of independent directors. This acquisition was accounted for as a transaction with an entity under common control whereby the acquisition was recorded at historical cost at the acquisition date.

On October 1, 2014, we acquired certain oil and natural gas properties in Weld County, Colorado from Memorial Resource for approximately $15.0 million in cash consideration.  The acquired properties represent working interests in wells located in the Wattenberg field (the “Wattenberg Acquisition”). Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee.  This acquisition has an effective date of October 1, 2014 and was accounted for as a transaction with an entity under common control whereby the acquisition was recorded at historical cost at the acquisition date.

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

	Double A			Wattenberg
	Acquisition			Acquisition
Oil and gas properties, net	$	37,838		$	9,822
Asset retirement obligations		(908	)		(149	)
Other current liabilities		(722	)		—
Total identifiable net assets	$	36,208		$	9,673

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

2013 Acquisitions

On March 28, 2013, we acquired all of the outstanding equity interests in WHT from operating subsidiaries of MRD LLC for a purchase price of $200.0 million, which included $4.0 million of working capital and other customary adjustments. This acquisition was funded with borrowings under our revolving credit facility and the net proceeds from our March 25, 2013 public offering of common units (including our general partner’s proportionate capital contribution). Terms of the transaction were approved by our general partner’s Board and by its conflicts committee. The WHT Properties consist of additional working interests in properties that we originally acquired in December 2011 in conjunction with our initial public offering. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands):

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

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Acquisition of Cinco Group Properties from Memorial Resource & NGP

On October 1, 2013, we acquired, through equity and asset transactions, oil and natural gas properties primarily in the Permian Basin, East Texas and the Rockies from MRD LLC and certain affiliates of NGP for an aggregate purchase price of approximately $603 million, subject to customary post-closing adjustments. The Cinco Group acquisition was funded with borrowings under our revolving credit facility. Terms of the transaction were approved by the Board and by its conflicts committee. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands):

Cash and cash equivalents	$	3,265
Accounts receivable		10,615
Prepaid expenses and other current assets		1,824
Oil and natural gas properties, net		457,439
Long-term derivative instruments, net		3,056
Other long-term assets		356
Accounts payable		(4,063	)
Revenue payable		(4,519	)
Accrued liabilities		(3,311	)
Short-term derivative instruments, net		(1,505	)
Asset retirement obligations		(13,575	)
Credit facilities		(151,690	)
Other long-term liabilities		(265	)
Net assets	$	297,627

2012 Acquisitions

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 final purchase price of $18.5 million after 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. 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. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands):

Oil and natural gas properties, net	$	15,164
Short-term derivative instruments, net		715
Long-term derivative instruments, net		674
Asset retirement obligations		(466	)
Accrued liabilities		(17	)
Net assets	$	16,070

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 final purchase price of $27.0 million after 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. These properties are located primarily in the Joaquin and Carthage fields in Panola and Shelby counties in East Texas. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands):

Oil and natural gas properties, net	$	31,716
Accounts receivable		612
Short-term derivative instruments, net		1,017
Long-term derivative instruments, net		1,337
Asset retirement obligations		(43	)
Accrued liabilities		(70	)
Net assets	$	34,569

F- 35

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

On December 12, 2012, we acquired REO, which owns certain operating interests in producing and non-producing oil and gas properties offshore Southern California, from Rise for a purchase price of $270.6 million, which included $3.0 million of working capital and other customary adjustments. The Beta acquisition was funded with borrowings under our credit facility and the net proceeds generated from our December 12, 2012 public offering of common units (including our general partner’s proportionate capital contribution). Terms of the transaction were approved by the Board and by its conflicts committee. The acquired properties, which we refer to as the Beta properties, primarily consist of a 51.75% working interest in three Pacific Outer Continental Shelf blocks covering the Beta Field, and are located in federal waters approximately eleven miles offshore the Port of Long Beach, California. Associated facilities include three conventional wellhead and production processing platforms, a 17.5-mile pipeline and an onshore tankage and metering facility. Two of the platforms are bridge connected and stand in approximately 260 feet of water, while the third platform stands in approximately 700 feet of water. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands):

Cash and cash equivalents	$	6,021
Accounts receivable		16,284
Short-term derivative instruments, net		2,926
Prepaid expenses and other current assets		4,521
Oil and natural gas properties, net		108,342
Restricted investments		68,009
Accounts payable		(9,092	)
Accrued liabilities		(9,140	)
Asset retirement obligations		(58,746	)
Credit facilities		(28,500	)
Deferred tax liability		(1,674	)
Noncontrolling interest		(5,255	)
Net assets	$	93,696

On December 12, 2012, in connection with the Beta acquisition, the Partnership contributed to MRD LLC the entity that employs those who operate and support the Beta properties in exchange for approximately $3.0 million. The net book value of the assets contributed to MRD LLC was as follows (in thousands):

Cash and cash equivalents	$	3,751
Accounts receivable		11,125
Prepaid expenses and other current assets		3,470
Property, plant and equipment, net		416
Accounts payable		(7,898	)
Accrued liabilities		(7,864	)
Net assets	$	3,000

Related Party Agreements

We and certain of our affiliates have entered into various documents and agreements. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations.

Omnibus Agreement

Memorial Resource continues to provide management, administrative and operating services for us and our general partner pursuant to our omnibus agreement. The following table summarizes the amount of general and administrative expenses recognized under the omnibus agreement that are reflected in the accompanying statements of operations for the periods presented (in thousands):

For the Year Ended December 31,
2014		2013		2012
$	24,372	$	9,440	$	1,771

Beta Management Agreement

In connection with the December 2012 Beta acquisition, Memorial Resource entered into a management agreement with its wholly-owned subsidiary, Beta Operating Company, LLC, pursuant to which Memorial Resource agreed to provide management and administrative oversight with respect to the services provided by such subsidiary under certain operating agreements with our

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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

An affiliate of REO collected a management fee for providing administrative services to REO prior to the Beta acquisition. These administrative services included accounting, business development, finance, legal, information technology, insurance, government regulations, communications, regulatory, environmental and human resources services. The following table summarizes the amount of management fees REO incurred and paid, which are included in general and administrative expenses in the accompanying statements of operations for the periods presented (in thousands):

For Twelve Months Ended December 31,
2012
$	1,552

WHT Management Agreement

WildHorse and Tanos, collectively owned the outstanding equity interests in WHT prior to March 28, 2013. Under the terms of a management agreement dated April 8, 2011, WildHorse provided executive, financial, accounting and land services to WHT. WildHorse also managed day-to-day field operations and drilling activities. Geological, executive and other services were provided by Tanos. To compensate for these services, WHT paid WildHorse and Tanos management fees totaling approximately $0.2 million per month. In connection with the WHT acquisition, the management agreement was terminated as of March 28, 2013. WildHorse collected an additional $0.6 million under a transitional agreement that was in place from April 2013 through July 2013.

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

Cinco Group Transition Service Agreements

The Partnership entered into transition service agreements with Propel Energy, Stanolind, and Boaz Energy Partners to ensure that ownership, operation, and maintenance of acquired properties could be smoothly transitioned. The term of these agreements were from October 1, 2013 through February 28, 2014. The Partnership paid transition service fees of approximately $0.8 million in the aggregate under these agreements.

Classic Pipeline Gas Gathering Agreement & Water Disposal Agreement

On November 1, 2011, Classic Hydrocarbons Operating, LLC (“Classic Operating”), which became our previous owner’s wholly-owned subsidiary in connection with their restructuring transactions, and Classic Pipeline & Gathering, LLC, a subsidiary of MRD Holdco (“Classic Pipeline”), entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. On May 1, 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed, and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement has a term until December 31, 2023, subject to one-year extensions at either party’s election.

On May 1, 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement has a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline.

In February 2015, in connection with the Property Swap, Classic Operating merged with and into OLLC.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Other Related Party Transactions

Director, Advisory & Financing Fees

Certain of the Cinco Group entities entered into an advisory service, reimbursement, and indemnification agreements with NGP. These agreements generally required that an annual advisory fee be paid to NGP. Fees paid under these agreements for the years ended December 31, 2013 and 2012 were approximately $0.3 million and $0.4 million, respectively. Certain of the Cinco Group entities also paid a financing fee equal to a percentage of the capital contributions raised by NGP. These fees were considered a syndication cost and reduced equity contributions for financing fees paid. Fees for the year ended December 31, 2012 were approximately $0.4 million. There were no fees during the year ended December 31, 2013.

Tanos Management Team Equity Interest

On April 1, 2013, Tanos’ management team sold its 1.066% membership interest in Tanos to MRD LLC and all incentive units held were forfeited. In connection with this sale, all of Tanos’ employees resigned and became employees of Tanos Exploration II, LLC (“Tanos II”), a Texas limited liability company controlled by the former management team of Tanos. Effective April 1, 2013, Tanos II entered into a Transition Services Agreement with Tanos, whereby Tanos II would manage the operations of Tanos for up to a 6-month period of time. Tanos II is an unrelated entity.

The governing documents of Tanos provided for the issuance of incentive units. Tanos granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units were entitled to distributions when declared, but only after cumulative distribution thresholds had been achieved (i.e., recovery of specified members’ capital contributions plus a rate of return). These incentive units were accounted for as liability awards with compensation expense based on period-end fair value. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. No compensation cost was recorded related to incentive units prior to the incentive units being forfeited on April 1, 2013. Compensation expense of approximately $5.8 million was recorded by Tanos and recognized as general and administrative expense during April 2013.

Classic Management Team Equity Interest

On November 1, 2013, Classic’s management team sold its membership interest in Classic to MRD LLC and all incentive units held were forfeited.    

The governing documents of Classic provided for the issuance of incentive units. Classic granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units were entitled to distributions when declared, but only after cumulative distribution thresholds had been achieved (i.e., recovery of specified members’ capital contributions plus a rate of return). These incentive units were accounted for as liability awards with compensation expense based on period-end fair value. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. No compensation cost was recorded related to incentive units prior to the incentive units being forfeited on November 1, 2013. Compensation expense of approximately $8.3 million was recorded by Classic and recognized as general and administrative expense during November 2013.

Miscellaneous

For the year ended December 31, 2014 the Partnership incurred gathering and salt water disposal fees of approximately $1.8 million from affiliates.

A company affiliated with one of the Classic’s employees provided certain land-related services to Classic.  Classic paid approximately $1.0 million to this affiliated company for these services in 2012.

During 2012, the Cinco Group received an equity contribution of $6.9 million of oil and gas properties in the Hendricks Field located in the Permian Basin of Texas by an NGP controlled entity. Due to common control considerations, this equity contribution was recorded at historical cost of the properties.

During 2012, Boaz reimbursed a member of its management team approximately $0.3 million in general, administrative, and lease operating expenses related to an oral lease agreement between the member of management and a third party for a field office and yard located in Bronte, Texas.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

See Note 3 for additional information regarding the divestiture of certain interests in oil and gas properties offshore Louisiana that the Cinco Group sold during 2012 to an NGP controlled entity.

Note 13. Commitments and Contingencies

Litigation & Environmental

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

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 contamination 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, 2014, 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:

	2014			2013			2012
	(In thousands)
Balance at beginning of period	$	437		$	1,051		$	1,747
Charged to costs and expenses		2,852			—			(225	)
Payments		(1,197	)		(614	)		(471	)
Balance at end of period	$	2,092		$	437		$	1,051

At December 31, 2014 and 2013, $2.1 million and $0.4 million, respectively, of our environmental reserves were classified as current liabilities in accrued liabilities.

Sinking Fund Trust Agreement

REO assumed an obligation with a third party to make payments into a sinking fund in connection with its 2009 acquisition of the Beta properties, the purpose of which is to provide funds adequate to decommission the portion of the San Pedro Bay pipeline that lies within State waters and the surface facilities. Under the terms of the agreement, REO, as the operator of the properties, is obligated to make monthly deposits into the sinking fund account in an amount equal to $0.25 per barrel of oil and other liquid hydrocarbon produced from the acquired working interest. Interest earned in the account stays in the account. The obligation to fund ceases when the aggregate value of the account reaches $4.3 million. As of December 31, 2014, the gross account balance included in restricted investments was approximately $2.7 million. REO’s maximum remaining obligation net to its 51.75% interest under the terms of the current agreement was $0.8 million at December 31, 2014.

Supplemental Bond for Decommissioning Liabilities Trust Agreement

REO assumed an obligation with the BOEM in connection with its 2009 acquisition of the Beta properties. Under the terms of the agreement dated March 1, 2007, the seller of the Beta properties was obligated to deliver a $90.0 million U.S. Treasury Note into a trust account for the decommissioning of the offshore production facilities. At the time of acquisition, all obligations under this existing agreement had been met.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

In January 2010, the BOEM issued a report that revised upward, the estimated cost of decommissioning. In June 2010, REO agreed to make additional quarterly payments to the trust account attributable to its net working interest of approximately $0.6 million beginning on June 30, 2010 until the payments and accrued interest attributable to REO equal $78.7 million by December 31, 2016. The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands):

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

In the event the account balance is less than the contractual amount, the working interest owners must make additional payments. Interest income earned and deposited in the trust account mitigates the likelihood that additional payments will have to be made by the working interest owners. As of December 31, 2014, the maximum remaining obligation net to REO’s interest was approximately $8.7 million.

The trust account is held by REO for the benefit of all working interest owners.

The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of December 31, 2014 (in thousands):

	Amortized
Investment	Cost
U.S. Bank Money Market Cash Equivalent	$	135,176
Less: Outside working interest owners share		(65,222	)
	$	69,954

Operating Leases

We have leases for offshore Southern California pipeline right-of-way use as well as office space in our operating regions. We also lease equipment and incur surface rentals related to our business operations. The previous owners also leased equipment and office space under various operating leases and incurred surface rentals related to their operations.

For the years ended December 31, 2014, 2013 and 2012, we recognized $6.4 million, $2.4 million and $1.0 million of rent expense, respectively. The previous owners recorded rent expense of approximately $0.5 million, $2.9 million and $2.3 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Amounts shown in the following table represent minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year (in thousands):

			Payment or Settlement Due by Period
Purchase commitment	Total		2015		2016		2017		2018		2019		Thereafter
Operating leases	$	3,665	$	788	$	416	$	205	$	205	$	205	$	1,846

Purchase Commitment Assumed

At December 31, 2014, we had a CO₂ purchase commitment with a third party that was assumed in our Wyoming Acquisition. The table below outlines our purchase commitment under the contract (in thousands):

			Payment or Settlement Due by Period
Purchase commitment	Total		2015		2016		2017		2018		2019		Thereafter
CO2 minimum purchase commitment	$	50,495	$	9,608	$	10,179	$	10,151	$	6,995	$	7,060	$	6,502

Note 14. Defined Contribution Plans

Memorial Resource sponsors a defined contribution plan for the benefit of 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.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

This plan became effective on January 1, 2012. The plan received employer contributions of approximately $1.4 million, $0.9 million, and $0.4 million in 2014, 2013, and 2012, respectively.

Effective January 1, 2012, REO assumed sponsorship of a separate defined contribution plan. This plan specifically benefits substantially all those employed by the Memorial Resource subsidiary that operates and supports the Beta properties that have attained 21 years of age. Eligible employees are permitted to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. Employer matching contributions of 100% of employee contributions that does not exceed 6% of compensation are made to the plan as well. The employer matching contributions associated with this plan were subject to a three-year graded vesting schedule through February 28, 2012. Effective March 1, 2012, the plan was amended to offer immediate vesting of employer matching contributions. The plan received employer contributions of approximately $0.6 million and $0.5 million in 2013 and 2012, respectively. Approximately $0.3 million associated with this plan are reflected as costs and expenses in the accompanying statements of operations for each of the years ended December 31, 2013, and 2012. This plan was terminated effective December 31, 2013.

Certain Cinco Group entities made matching contributions to defined contribution plans for the benefit of their eligible employees. Matching employer contributions of approximately $0.1 million and $0.2 million were made to these plans in 2013 and 2012, respectively. Such contributions to these plans are included in general and administrative expenses in the accompanying combined statements of operations.

Note 15. Income Tax

Income tax benefit (expense) for the indicated periods is comprised of the following:

	For the Year Ended December 31,
	2014			2013			2012
	(In thousands)
Current taxes:
Federal	$	—		$	—		$	—
State		(127	)		(308	)		(285	)
Deferred taxes:
Federal		2,057			—			—
State		(509	)		—			177
Total income tax benefit (expense)	$	1,421		$	(308	)	$	(108	)

The actual income tax benefit (expense) differs from the expected income tax benefit (provision) as computed by applying the federal statutory corporate tax rate of 35% for each period indicated as follows:

	For the Year Ended December 31,
	2014			2013			2012
Expected tax benefit (expense)	$	(39,966	)	$	(21,459	)	$	(8,111	)
State income tax expense, net of federal benefit		(1,907	)		(308	)		(108	)
Pass-through entities		42,000			21,459			8,111
Other		1,294			—			—
Total income tax benefit (expense)	$	1,421		$	(308	)	$	(108	)

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The components of net deferred income tax assets and (liabilities) recognized were as follows:

	December 31,
	2014			2013
	(In thousands)
Deferred current income tax assets:
Unrealized hedging transactions	$	—		$	37
Accrued liabilities		—			5
Other		16			(42	)
Deferred current income tax assets:	$	16		$	—
Deferred current income tax liabilities:
Unrealized hedging transactions	$	(1,346	)		—
Other		(61	)		(382	)
Deferred current income tax liabilities:	$	(1,407	)	$	(382	)
Deferred noncurrent income tax assets:
Net operating loss carryforward	$	3,959		$	2,350
Asset retirement obligation		1,855			971
Other		14			14
Net deferred tax valuation allowance		(2,633	)		(2,910	)
Deferred noncurrent income tax assets:	$	3,195		$	425
Deferred noncurrent income tax liabilities:
Property, plant and equipment	$	(32,094	)	$	(3,220	)
Unrealized hedging transactions		(2,042	)		(312	)
Other		1			—
Deferred noncurrent income tax liabilities:	$	(34,135	)	$	(3,532	)
Net current deferred income tax assets (liabilities)	$	(1,391	)	$	(382	)
Net noncurrent deferred income tax assets (liabilities)	$	(30,940	)	$	(3,107	)

We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more-likely-than-not sustainable based on its technical merits.  For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The Partnership and the previous owners had no unrecognized tax benefits for the years ended December 31, 2014, 2013 or 2012.

Generally, the Partnership and previous owner's income tax years 2011 through 2014 remain open and subject to examination by Federal tax authorities or state tax authorities where the Partnership or previous owners conduct operations. In certain jurisdictions, the Partnership and the previous owners operate through more than one legal entity, each of which may have different open years subject to examination.

The Partnership recognizes interest and penalties accrued to unrecognized benefits in Other income (expense) in its consolidated and combined statements of operations. For the years ended December 31, 2014, 2013 and 2012, the Partnership recognized no interest and penalties.

As of December 31, 2014, the Partnership and the previous owner had available, to reduce future taxable income, a United States net operating loss carryforwards (NOLs) of approximately $11.1 million before consideration of any valuation allowance which expires in the years 2027 through 2034.  A portion of these NOLs are subject to the ownership change limitation provisions of Section 382 of the Internal Revenue Code (IRC). The Partnership and the previous owner also had various net state NOL carryforwards of approximately $2.9 million, before consideration of any valuation allowance with varying lengths of allowable carryforward periods ranging from 10 to 20 years that can be used to offset future state taxable income.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 16. Quarterly Financial Information (Unaudited)

The following tables present selected quarterly financial data for the periods indicated. Earnings per unit are computed independently for each of the quarters presented and the sum of the quarterly earnings per unit may not necessarily equal the total for the year.

	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter
	(In thousands, except per unit amounts)
For the Year Ended December 31, 2014:
Revenues	$	111,649		$	136,290		$	158,399		$	129,881
Operating income (loss)		(16,739	)		(93,294	)		127,078			181,355
Net income (loss)		(32,892	)		(111,640	)		101,307			158,839
Net income (loss) attributable to Memorial Production Partners LP		(32,947	)		(111,628	)		101,157			159,000
Net income (loss) allocated to previous owners		1,165			2,566			(1,919	)		(4,277	)
Net income (loss) noncontrolling interest		55			(12	)		150			(161	)
Limited partners’ interest in net income (loss)		(34,118	)		(114,120	)		102,925			163,066
Basic and diluted earnings per unit		(0.56	)		(1.86	)		1.39			1.88

	First			Second		Third			Fourth
	Quarter			Quarter		Quarter			Quarter
	(In thousands, except per unit amounts)
For the Year Ended December 31, 2013:
Revenues	$	75,074		$	96,907	$	99,807		$	101,349
Operating income (loss)		(1,341	)		65,253		24,401			17,300
Net income (loss)		(8,535	)		56,413		12,098			1,029
Net income (loss) attributable to Memorial Production Partners LP		(8,531	)		56,315		11,972			982
Net income (loss) allocated to previous owners		(3,509	)		10,136		55,265			(9,880	)
Net income (loss) noncontrolling interest		(4	)		98		126			47
Limited partners’ interest in net income (loss)		(5,017	)		46,133		(43,270	)		10,831
Basic and diluted earnings per unit		(0.14	)		1.04		(0.97	)		0.18

The Partnership consummated several common control acquisitions in 2013, as further discussed in Note 12, directly or indirectly from Memorial Resource and certain affiliates of NGP. The quarterly financial information for the years ended December 31, 2014 and 2013 presented above has been retrospectively revised for these common control transactions and for the Property Swap as discussed in Notes 1 and 18.  See Notes 2 and 10 for additional information regarding earnings per unit.

Note 17. 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.

	Years Ended December 31,
	2014			2013			2012
	(In thousands)
Evaluated oil and natural gas properties	$	3,329,338		$	2,077,344		$	1,849,457
Support equipment and facilities		185,997			5,910			5,760
Unevaluated oil and natural gas properties		—			1,960			6,964
Accumulated depletion, depreciation, and amortization		(1,057,398	)		(462,742	)		(345,579	)
Total	$	2,457,937		$	1,622,472		$	1,516,602

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND 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,
	2014		2013		2012
	(In thousands)
Property acquisition costs, proved	$	983,076	$	37,786	$	278,246
Property acquisition costs, unproved		720		—		—
Exploration		—		—		42,430
Development  (1)		306,751		164,920		99,395
Total	$	1,290,547	$	202,706	$	420,071

(1)      Amounts do not include costs for SPBPC and related support equipment.

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.

We engaged NSAI and Ryder Scott to audit our reserves estimates for approximately 86% of our estimated proved reserves (by volume) at December 31, 2014. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.

The weighted-average 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:

	2014		2013		2012
Oil ($/Bbl):
WTI (1)	$	91.48	$	93.42	$	91.22
NGL ($/Bbl):
WTI (1)	$	91.48	$	93.42	$	91.27
Natural Gas ($/MMbtu):
Henry Hub (2)	$	4.35	$	3.67	$	2.76

(1)      The weighted average WTI price was adjusted by lease for quality, transportation fees, and a regional price differential.

(2)      The weighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The following tables set forth estimates of the net reserves as of December 31, 2014, 2013 and 2012, respectively:

		Year Ended December 31, 2014
		Oil			Gas			NGLs			Equivalent
		(MBbls)			(MMcf)			(MBbls)			(MMcfe)
Proved developed and undeveloped reserves:
	Beginning of year		39,635			737,908			35,794			1,190,484
	Extensions and discoveries		849			12,783			711			22,145
	Purchase of minerals in place		69,095			13,036			22,351			561,713
	Production		(3,134	)		(48,721	)		(2,498	)		(82,518	)
	Revision of previous estimates		(6,187	)		12,210			2,676			(8,864	)
	End of year		100,258			727,216			59,034			1,682,960
Proved developed reserves:
	Beginning of year		22,429			427,983			17,637			668,381
	End of year		54,723			417,247			37,260			969,141
Proved undeveloped reserves:
	Beginning of year		17,206			309,925			18,157			522,103
	End of year		45,535			309,969			21,774			713,819

		Year Ended December 31, 2013
		Oil			Gas			NGLs			Equivalent
		(MBbls)			(MMcf)			(MBbls)			(MMcfe)
Proved developed and undeveloped reserves:
	Beginning of year		40,822			794,369			39,554			1,276,625
	Extensions and discoveries		5,814			85,455			4,353			146,463
	Purchase of minerals in place		119			16,294			258			18,554
	Production		(1,797	)		(41,287	)		(1,806	)		(62,910	)
	Revision of previous estimates		(5,323	)		(116,923	)		(6,565	)		(188,248	)
	End of year		39,635			737,908			35,794			1,190,484
Proved developed reserves:
	Beginning of year		24,784			441,858			18,060			698,922
	End of year		22,429			427,983			17,637			668,381
Proved undeveloped reserves:
	Beginning of year		16,038			352,511			21,494			577,703
	End of year		17,206			309,925			18,157			522,103

		Year Ended December 31, 2012
		Oil			Gas			NGLs			Equivalent
		(MBbls)			(MMcf)			(MBbls)			(MMcfe)
Proved developed and undeveloped reserves:
	Beginning of year		31,630			1,138,112			50,245			1,629,362
	Extensions and discoveries		7,618			29,824			1,697			85,714
	Purchase of minerals in place		11,336			113,617			7,095			224,203
	Production		(1,565	)		(38,129	)		(830	)		(52,499	)
	Sales of minerals in place		(4,214	)		(4,214	)		—			(29,498	)
	Revision of previous estimates		(3,983	)		(444,841	)		(18,653	)		(580,657	)
	End of year		40,822			794,369			39,554			1,276,625
Proved developed reserves:
	Beginning of year		19,535			470,116			11,045			653,596
	End of year		24,784			441,858			18,060			698,922
Proved undeveloped reserves:
	Beginning of year		12,095			667,996			39,200			975,766
	End of year		16,038			352,511			21,494			577,703

Noteworthy amounts included in the categories of proved reserve changes in the above tables include:

· We acquired 561.7 Bcfe in multiple acquisitions during the year ended December 31, 2014, the largest being the Wyoming Acquisition of 497.2 Bcfe.  We also acquired 45.0 Bcfe from the Eagle Ford Acquisition. An upward revision

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

of natural gas for the year ended December 31, 2014 was due to increased natural gas prices on the Classic properties.  The upward revision was partially offset by a downward revision of natural gas for the year ended December 31, 2014, which was primarily due to updated well performance data in certain East Texas fields. Proved undeveloped reserves increased during the year ended December 31, 2014 primarily due to the Wyoming Acquisition.

· We acquired 224.2 Bcfe in multiple acquisitions during the year ended December 31, 2012, the largest being the Goodrich Acquisition of 148.9 Bcfe. Stanolind acquired 43.6 Bcfe through multiple acquisitions, the largest being the Menemsha Acquisition of 23.9 Bcfe. During the year ended December 31, 2012, Propel divested 19.0 Bcfe of offshore Louisiana oil and gas properties to an NGP controlled entity.

See Note 3 for additional information on acquisitions and divestitures.

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,
	2014			2013			2012
	(In thousands)
Future cash inflows	$	14,190,450		$	7,672,312		$	7,478,131
Future production costs		(4,821,051	)		(2,963,146	)		(2,537,077	)
Future development costs		(1,455,926	)		(901,374	)		(818,228	)
Future income tax expense (1)		(119,675	)		—			—
Future net cash flows for estimated timing of cash flows		7,793,798			3,807,792			4,122,826
10% annual discount for estimated timing of cash flows		(4,881,811	)		(2,089,588	)		(2,350,586	)
Standardized measure of discounted future net cash flows	$	2,911,987		$	1,718,204		$	1,772,240

(1) We are subject to the Texas margin 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 years ended December 31, 2014, 2013 and 2012. Amount relates to Classic since its reserves were a part of a taxable entity for federal income state purposes at December 31, 2014.

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, 2014:

	Years Ended December 31,
	2014			2013			2012
	(In thousands)
Beginning of year	$	1,718,204		$	1,772,240		$	2,261,764
Sale of oil and natural gas produced, net of production costs		(354,932	)		(255,031	)		(186,798	)
Purchase of minerals in place		1,489,477			23,160			375,953
Sale of minerals in place		—			—			(154,963	)
Extensions and discoveries		44,843			150,631			272,761
Changes in income taxes, net		(63,180	)		—			1,947
Changes in prices and costs		(170,682	)		(26,648	)		(520,852	)
Previously estimated development costs incurred		275,078			199,775			117,793
Net changes in future development costs		(133,098	)		(16,219	)		(16,074	)
Revisions of previous quantities		(48,087	)		(373,109	)		(573,725	)
Accretion of discount		171,820			177,223			226,371
Change in production rates and other		(17,456	)		66,182			(31,937	)
End of year	$	2,911,987		$	1,718,204		$	1,772,240

Note 18. Subsequent Events

2015 Acquisition

On February 23, 2015, we and Memorial Resource completed a transaction in which we exchanged our oil and gas properties in North Louisiana and approximately $78 million in cash for Memorial Resource’s East Texas and West Louisiana oil and gas

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

properties.  Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee, which is comprised entirely of independent directors.  This transaction has an effective date of January 1, 2015.

Conversion of Subordinated Units

The subordination period for the 5,360,912 subordinated units ended on February 13, 2015.  All of the subordinated units, which were owned by MRD Holdco, converted to common units on a one-to-one basis at the end of the subordination period.

2015 Repurchases of Common Units

We repurchased an additional $28.5 million in common units, which represents a repurchase and retirement of 1,909,583 common units under the MEMP Repurchase Program through February 1, 2015.  

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