mrd-ex992_2015070812.htm

We have audited the accompanying consolidated and combined balance sheets of Memorial Resource Development Corp. and subsidiaries (the Company) as of December 31, 2014 and 2013, and the related 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 consolidated and combined financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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 consolidated and combined financial statements referred to above present fairly, in all material respects, the financial position of Memorial Resource Development Corp. 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 consolidated and combined financial statements, the balance sheets and the related statements of operations, equity, and cash flows have been prepared on a combined basis of accounting.

	December 31,
	2014			2013
ASSETS
Current assets:
Cash and cash equivalents	$	5,958		$	77,721
Restricted cash		—			35,000
Accounts receivable:
Oil and natural gas sales		82,263			68,764
Joint interest owners and other		49,313			19,958
Affiliates		—			4,652
Short-term derivative instruments		340,056			9,289
Prepaid expenses and other current assets		28,027			19,513
Total current assets		505,617			234,897
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		4,844,529			3,037,298
Other		33,815			10,331
Accumulated depreciation, depletion and impairment		(1,340,688	)		(627,925	)
Property and equipment, net		3,537,656			2,419,704
Long-term derivative instruments		435,369			48,616
Restricted investments		77,361			73,385
Restricted cash		260			15,506
Other long-term assets		37,284			37,053
Total assets	$	4,593,547		$	2,829,161

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	25,772		$	20,734
Accounts payable - affiliates		624			1,975
Revenues payable		57,352			56,091
Accrued liabilities		199,000			98,130
Short-term derivative instruments		3,289			9,711
Total current liabilities		286,037			186,641
Long-term debt - MRD Segment		783,000			871,150
Long-term debt - MEMP Segment		1,595,413			792,067
Asset retirement obligations		122,531			111,679
Long-term derivative instruments		—			6,080
Deferred tax liabilities		95,017			3,106
Other long-term liabilities		8,585			306
Total liabilities		2,890,583			1,971,029
Commitments and contingencies (Note 16)
Equity:
Stockholders' equity (deficit):
Preferred stock, $.01 par value: 50,000,000 shares authorized; no shares issued and outstanding		—			—
Common stock, $.01 par value: 600,000,000 shares authorized; 193,435,414 shares issued and outstanding at December 31, 2014; no shares authorized, issued or outstanding at December 31, 2013		1,935			—
Additional paid-in capital		1,367,346			—
Accumulated earnings (deficit)		(786,871	)		—
Total stockholders' equity		582,410			—
Members' equity:
Members		—			237,186
Previous owners (Note 1)		—			40,331
Total members' equity		—			277,517
Noncontrolling interests		1,120,554			580,615
Total equity		1,702,964			858,132
Total liabilities and equity	$	4,593,547		$	2,829,161

	For Year Ended December 31,
	2014			2013			2012
Revenues:
Oil & natural gas sales	$	894,967		$	571,948		$	393,631
Other revenues		4,378			3,075			3,237
Total revenues		899,345			575,023			396,868

Costs and expenses:
Lease operating		161,303			113,640			103,754
Pipeline operating		2,068			1,835			2,114
Exploration		16,603			2,356			9,800
Production and ad valorem taxes		45,751			27,146			23,624
Depreciation, depletion, and amortization		314,193			184,717			138,672
Impairment of proved oil and natural gas properties		432,116			6,600			28,871
Incentive unit compensation expense		943,949			43,279			9,510
General and administrative		87,673			82,079			59,677
Accretion of asset retirement obligations		6,306			5,581			5,009
(Gain) loss on commodity derivative instruments		(749,988	)		(29,294	)		(34,905	)
(Gain) loss on sale of properties		3,057			(85,621	)		(9,761	)
Other, net		(12	)		649			502
Total costs and expenses		1,263,019			352,967			336,867
Operating income (loss)		(363,674	)		222,056			60,001
Other income (expense):
Interest expense, net		(133,833	)		(69,250	)		(33,238	)
Loss on extinguishment of debt		(37,248	)		—			—
Amortization of investment premium		—			—			(194	)
Other, net		(337	)		145			535
Total other income (expense)		(171,418	)		(69,105	)		(32,897	)
Income (loss) before income taxes		(535,092	)		152,951			27,104
Income tax benefit (expense)		(100,971	)		(1,619	)		(107	)
Net income (loss)		(636,063	)		151,332			26,997
Net income (loss) attributable to noncontrolling interest		126,788			49,830			(2,701	)
Net income (loss) attributable to Memorial Resource Development Corp.		(762,851	)		101,502			29,698
Net (income) loss allocated to members		(20,305	)		(90,712	)		7,620
Net (income) loss allocated to previous owners		(1,425	)		(10,790	)		(37,318	)
Net income (loss) available to common stockholders	$	(784,581	)	$	—		$	—

Earnings per common share: (Note 10)
Basic	$	(4.08	)	$	—		$	—
Diluted	$	(4.08	)	$	—		$	—
Weighted average common and common equivalent shares outstanding:
Basic		192,498			—			—
Diluted		192,498			—			—

	For Year Ended December 31,
	2014			2013			2012
Cash flows from operating activities:
Net income (loss)	$	(636,063	)	$	151,332		$	26,997
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization		314,193			184,717			138,672
Impairment of proved oil and natural gas properties		432,116			6,600			28,871
(Gain) loss on derivatives		(749,843	)		(29,533	)		(29,323	)
Cash settlements (paid) received on derivative instruments		20,559			30,403			72,045
Cash settlements on terminated derivatives		5,326			—			—
Premiums paid for derivatives		(6,065	)		—			(411	)
Loss on extinguishment of debt		30,248			—			—
Amortization of deferred financing costs		7,436			8,343			3,584
Accretion of senior notes net discount		2,501			554			—
Amortization of investment premium		—			—			194
Accretion of asset retirement obligations		6,306			5,581			5,009
Amortization of equity awards		10,678			3,557			1,423
(Gain) loss on sale of properties		3,057			(85,621	)		(9,761	)
Non-cash compensation expense		916,218			1,057			—
Exploration costs		14,953			181			6,980
Deferred income tax expense (benefit)		100,230			76			(312	)
Changes in operating assets and liabilities:
Accounts receivable		(17,635	)		(15,758	)		(7,382	)
Prepaid expenses and other assets		(7,424	)		(2,986	)		(1,574	)
Payables and accrued liabilities		21,208			19,320			5,392
Other		8,272			—			—
Net cash provided by operating activities		476,271			277,823			240,404
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(1,177,670	)		(105,762	)		(360,678	)
Additions to oil and gas properties		(674,396	)		(360,015	)		(273,334	)
Additions to other property and equipment		(17,067	)		(2,670	)		(2,674	)
Additions to restricted investments		(3,976	)		(5,361	)		(4,599	)
Deposits for property acquisitions		(215	)		—			—
Decrease (increase) in restricted cash		49,946			(49,347	)		(3	)
Proceeds from the sale of oil and natural gas properties		6,700			155,712			34,521
Other		(301	)		—			29
Net cash used in investing activities		(1,816,979	)		(367,443	)		(606,738	)
Cash flows from financing activities:
Advances on revolving credit facilities		2,746,800			1,132,755			619,450
Payments on revolving credit facilities		(2,457,900	)		(1,766,037	)		(251,569	)
Proceeds from the issuances of senior notes		1,092,425			1,031,563			—
Redemption of senior notes		(351,808	)		—			—
Borrowings under second lien credit facility		—			325,000			—
Redemption of second lien credit facility		(328,282	)		—			—
Deferred financing costs		(30,334	)		(41,175	)		(3,501	)
Proceeds from initial public offering		408,500			—			—
Costs incurred in conjunction with initial public offering		(28,373	)		—			—
Proceeds from MEMP public offering		553,288			511,204			202,573
Costs incurred in conjunction with MEMP public offering		(12,510	)		(21,066	)		(8,268	)
Proceeds from changes in ownership interests in MEMP		—			135,012			—
Repurchased shares under repurchase program		(161	)		—			—
Repurchases under MEMP unit repurchase program		(11,531	)		—			—
Restricted MEMP units returned to plan		(1,012	)		—			—
Purchase of additional interests in consolidated subsidiaries		(3,292	)		(15,135	)		—
Contributions from previous owners		—			1,214			44,072
Contributions from NGP affiliates related to sale of properties		1,165			2,013			45,158
Distributions to the Funds		—			(732,362	)		—
Distributions to MRD Holdco		(59,803	)		—			—
Distributions to noncontrolling interests		(149,084	)		(78,083	)		(15,208	)
Distribution to NGP affiliates related to purchase of assets		(66,693	)		(355,494	)		(242,174	)
Distribution to NGP affiliates related to sale of assets, net of cash received		(32,770	)		—			—
Distributions made by previous owners		—			(4,005	)		(28,772	)
Cash retained by previous owners		—			(7,909	)		—
Other		320			455			—
Net cash provided by financing activities		1,268,945			117,950			361,761
Net change in cash and cash equivalents		(71,763	)		28,330			(4,573	)
Cash and cash equivalents, beginning of period		77,721			49,391			53,964
Cash and cash equivalents, end of period	$	5,958		$	77,721		$	49,391

	Members' Equity
	Members			Previous Owners			Noncontrolling Interest			Total
Balance, December 31, 2011	$	853,436		$	261,340		$	161,588		$	1,276,364
Net income (loss)		(7,620	)		37,318			(2,701	)		26,997
Contributions		—			44,072			—			44,072
Contribution of oil and gas properties from NGP affiliate		—			6,893			—			6,893
Net proceeds from MEMP public equity Offering		—			—			194,134			194,134
Distributions		—			(28,772	)		(15,255	)		(44,027	)
Net book value of net assets acquired from affiliates		52,217			(93,696	)		41,479			—
Amortization of MEMP equity awards		—			—			1,423			1,423
Noncontrolling interest's share of net book value in excess of consideration received from sale of assets to MEMP		727			—			(727	)		—
Contribution related to sale of assets to NGP affiliate		6,291			40,138			742			47,171
Net book value of assets acquired by NGP affiliate		(579	)		(33,859	)		(68	)		(34,506	)
Distribution to affiliate in connection with acquisition of assets		(134,964	)		—			(107,210	)		(242,174	)
Impact from equity transactions of MEMP		41,930			—			(41,930	)		—
Other		176			(1	)		187			362
Balance, December 31, 2012		811,614			233,433			231,662			1,276,709
Net income (loss)		90,712			10,790			49,830			151,332
Contributions		—			1,214			—			1,214
Net Proceeds from MEMP public equity offering		—			—			490,138			490,138
Sale of MEMP common units		60,701			—			74,311			135,012
Distributions		(732,362	)		(4,005	)		(78,083	)		(814,450	)
Net book value of net assets acquired from affiliates		50,751			(181,556	)		130,805			—
Amortization of MEMP equity awards		—			—			3,558			3,558
Noncontrolling interest's share of cash consideration received in excess of the net book value sold to MEMP		(24	)		—			24			—
Distribution to affiliate in connection with acquisition of assets		(98,180	)		—			(253,055	)		(351,235	)
Purchase of noncontrolling interests		(303	)		—			(14,832	)		(15,135	)
Impact of equity transactions of MEMP		54,183			—			(54,183	)		—
Other		94			(2,299	)		440			(1,765	)
Net assets retained by previous owners		—			(17,246	)		—			(17,246	)
Balance, December 31, 2013	$	237,186		$	40,331		$	580,615		$	858,132

	Stockholders' Equity									Members' Equity
	Common stock			Additional paid in capital			Accumulated earnings (deficit)			Members			Previous Owners			Noncontrolling Interest			Total
Balance, December 31, 2013	$	—		$	—		$	—		$	237,186		$	40,331		$	580,615		$	858,132
Net income (loss)		—			—			(784,581	)		20,305			1,425			126,788			(636,063	)
Issuance of shares in connection with restructuring transactions (Note 1)		1,710			913,152			—			—			—			—			914,862
Issuance of shares in connection with initial public offering (Note 1)		215			379,962			—			—			—			—			380,177
Tax related effects in connection with restructuring transactions and initial public offering		—			(43,251	)		—			—			—			—			(43,251	)
Share repurchase		(1	)		—			(2,214	)		—			—			—			(2,215	)
Restricted stock awards		11			(11	)		—			—			—			—			—
Amortization of restricted stock awards		—			2,804			—			—			—			—			2,804
Contribution related to MRD Holdco incentive unit compensation expense (Note 12)		—			111,866			—			—			—			—			111,866
Purchase of noncontrolling interests		—			(2,881	)		—			—			—			(411	)		(3,292	)
Contribution related to sale of assets to NGP affiliate		—			—			—			1,165			—			—			1,165
Net book value of assets sold to NGP affiliate		—			—			—			(621	)		—			—			(621	)
Net book value of assets acquired from NGP affiliates		—			—			—			45,059			(41,756	)		—			3,303
Distribution to NGP affiliates in connection with acquisition of assets		—			—			—			(66,693	)		—			—			(66,693	)
Distribution of net assets to MRD Holdco		—			—			—			(123,078	)		—			29,994			(93,084	)
Distribution of shares received in connection with restructuring transactions to MRD Holdco		—			—			—			(110,510	)		—			—			(110,510	)
Net equity deemed contribution (distribution) related to net assets transferred to MEMP		—			5,327			—			(2,659	)		—			(2,668	)		—
Net proceeds from MEMP public equity offering		—			—			—			—			—			540,698			540,698
Distributions		—			—			—			—			—			(149,084	)		(149,084	)
Amortization of MEMP equity awards		—			—			—			—			—			7,874			7,874
MEMP common units repurchased		—			—			—			—			—			(12,903	)		(12,903	)
MEMP restricted units repurchased		—			—			—			—			—			(1,012	)		(1,012	)
Other		—			378			(76	)		(154	)		—			663			811
Balance, December 31, 2014	$	1,935		$	1,367,346		$	(786,871	)	$	—		$	—		$	1,120,554		$	1,702,964

Memorial Resource Development Corp. (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries.

The Company was formed by Memorial Resource Development LLC (“MRD LLC”) in January 2014 to acquire, explore and develop natural gas and oil properties in North America. MRD LLC was a Delaware limited liability company formed on April 27, 2011 by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to explore, develop and acquire natural gas and oil properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”). MRD LLC’s consolidated and combined financial statements represent our predecessor for accounting and financial reporting purposes prior to our initial public offering.

On June 18, 2014, the Company completed its initial public offering of 21,500,000 common units at a price of $19.00 per share, which generated net proceeds to the Company of approximately $380.2 million after deducting underwriting discounts and commissions and other offering related fees and expenses. The following restructuring events and transactions occurred in connection with our initial public offering:

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

Our audited financial statements reported herein include the financial position and results attributable to: (i) those certain oil and natural gas properties and related assets that MEMP acquired through equity transactions in October 2013 from Boaz Energy Partners, Crown Holdings, Propel Energy and Stanolind and (ii) NGPCIF NPI.

The financial statements reported herein include the financial position and results attributable to both our predecessor and the previous owners on a combined basis for periods prior to our initial public offering. For periods after the completion of our public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Due to our control of MEMP through our ownership of MEMP GP, we are required to consolidate MEMP for accounting and financial reporting purposes. MEMP is owned 99.9% by its limited partners and 0.1% by MEMP GP.

All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

We have two reportable business segments, both of which are engaged in the acquisition, exploration, development and production of oil and natural gas properties (See Note 14). Our reportable business segments are as follows:

Segment financial information has been retrospectively revised for the following common control transactions for comparability purposes:

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

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

Our consolidated financial statements include our accounts and those of our 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 our predecessor and the previous owners as discussed above. All material intercompany balances and transactions have been eliminated. Certain prior period balances have been reclassified to better align with financial statement presentation in the current fiscal year.

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

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.

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 MEMP’s offshore Southern California oil and gas properties. These restricted investments may 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 our predecessor 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, our predecessor, 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 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 oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves.

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.

The estimates of proved oil and natural gas reserves utilized in the preparation of the 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. Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, was engaged to audit our internally prepared reserves estimates at December 31, 2014. MEMP engaged NSAI and Ryder Scott Company, L.P. to audit MEMP’s internally prepared reserves estimates for all of MEMP’s 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 and equipment is stated at historical cost and is comprised primarily of vehicles, furniture, fixtures, office build-out cost 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 seven years.

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.

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 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 $432.1 million, $6.6 million, $28.9 million, respectively. See Note 4 for further discussion on impairments.

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s 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 consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information.

These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which 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 $7.4 million, $8.3 million and $3.6 million, respectively.

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:

Commodity derivative financial instruments (e.g., swaps, collars, and put options) are used to reduce the impact of natural gas, NGL and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument 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.

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 within intangible drilling costs and amortized using the units of production method. For the year ended December 31, 2014, we capitalized $7.3 million of interest. We did not capitalize any interest in 2013 or 2012.

Prior to our initial public offering, MRD LLC was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes; however, certain of its consolidating subsidiaries were taxed as corporations and subject to federal income taxes. We are organized as a taxable C corporation and subject to federal and certain state income taxes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax.

The Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

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. If a tax position meets such criteria, the tax effect that would be recognized by us would be the largest amount of benefit with more than 50% chance of being realized.

The evaluation of uncertain tax positions is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the consolidated financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.

The Company has no liability for unrecognized tax benefits as of December 31, 2014 and 2013. Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statements of operations or consolidated balance sheets as of December 31, 2014. In addition, the Company does not believe that there are any positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease within the next twelve months.

In June 2014, we recorded a deferred tax liability of approximately $43.3 million in stockholders’ equity in connection with our initial public offering and the related restructuring transactions. The tax bases of our assets and liabilities changed as a result our initial public offering and the related restructuring transactions, which represented a transaction among stockholders.

Tax audits may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which may be due upon the conclusion of these audits. Estimates of these tax liabilities are made based upon prior experience and are updated for changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, it is possible that the ultimate resolution of audits may result in liabilities which could be materially different from these estimates. See Note 15 for additional information.

Basic earnings per share (“EPS”) is computed using the two-class method based on net income (loss) available to common stockholders and the average number of shares of common stock outstanding for the period. Diluted EPS includes the impact of the Company’s restricted shares of common stock as they are participating securities. The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. See Note 10 for additional information.

The fair value of equity-classified awards (e.g., restricted stock 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 re-measured at each reporting period. Generally, no compensation expense is recognized for equity instruments that do not vest.

Prior to the restructuring transactions, the governing documents of MRD LLC and certain of its subsidiaries provided for the issuance of incentive units. 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.

In connection with the restructuring transactions, the MRD LLC incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. While any such distributions made by MRD Holdco will not involve any cash payment by us, we will be required to recognize non-cash compensation expense, which may be material, in future periods. The compensation expense recognized by us related to the incentive units will be offset by a deemed capital contribution from MRD Holdco as they are remeasured at the end of each reporting period.

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

	For Year Ended December 31,
	2014		2013		2012
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$	130,732	$	61,140	$	23,525
Income tax paid		838		168		22
Noncash investing and financing activities:
Change in capital expenditures in payables and accrued liabilities		31,771		41,017		17,158
Assumptions of asset retirement obligations related to properties acquired or drilled		5,420		4,227		7,962
Contribution of oil and gas properties from NGP affiliate		—		—		6,893
Accrued distribution to NGP affiliates related to Cinco Group acquisitions		—		4,352		—
Contribution related to sale of assets to NGP affiliate - restricted cash		—		—		2,013
Accrued equity offering costs		—		—		171
Distributions to noncontrolling interests		—		—		47
Repurchase of equity under repurchase program		3,425		—		—
Accounts receivable related to acquisitions		9,569		—		—

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

Amendments to Consolidation Analysis. In February 2015, the FASB issued an accounting standards update to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. Although the Company is currently assessing the impact of adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures, we expect that MEMP will become a VIE. We will either: (i) continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements or (ii) no longer consolidate MEMP under the revised VIE consolidation requirements and provide disclosures that apply to variable interest holders that do not consolidate a VIE. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosures.

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 Company’s financial position, results of operations and cash flows.

The third party acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, we, our predecessor, 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 equity offerings, 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.

MEMP has consummated several common control acquisitions since completing its initial public offering in December 2011, as further discussed in Note 13, from certain affiliates of NGP. These acquisitions were each 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.

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):

On December 30, 2014, MRD acquired certain oil and natural gas producing properties from third parties in the Terryville Complex for approximately $71.9 million, including estimated customary post-closing adjustments (the “Louisiana Acquisition”).

During the fourth quarter 2014, MRD acquired incremental interests in certain oil and gas properties and leases in the Terryville Complex from third parties in four separate transactions for an aggregate purchase price of approximately $24.0 million.

On July 1, 2014, MEMP consummated a transaction to acquire certain oil and natural gas liquids properties from a third party in Wyoming for an aggregate purchase price of approximately $906.1 million, including estimated post-closing adjustments (the “Wyoming Acquisition”). Revenues of $72.0 million were recorded in the statement of operations generated earnings of approximately $22.9 million related to the Wyoming Acquisition subsequent to the closing date.

On March 25, 2014, MEMP closed a transaction to acquire certain oil and natural gas producing properties from a third party in the Eagle Ford for approximately $168.1 million (the “Eagle Ford Acquisition”). In addition, MEMP 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 MEMP generated earnings of approximately $16.3 million.

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

The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2014 and 2013 as though the 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 Company 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 acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

On May 9, 2014, MRD LLC sold certain producing and non-producing properties in the Mississippian oil play of Northern Oklahoma to a third party for approximately $7.6 million and recorded a loss of $3.2 million.

On April 30, 2013, WildHorse Resources purchased certain oil and gas properties and leases in Louisiana from a third party for approximately $67.1 million.

MEMP closed two separate transactions during 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.

During 2013, Propel Energy acquired incremental interests in certain oil and gas properties and leases in the Hendrick Field located in Winkler County, Texas from third parties in three separate transactions for an aggregate purchase price of approximately $9.3 million.

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 purchase price of $1.5 million. The maximum allowable additional proceeds are $2.0 million. The contingent consideration is based on the natural gas pipeline servicing any new wells that Tanos drills in the area over the following three years. The contingent consideration portion of an arrangement is recorded when the consideration is determined to be realizable. Tanos recorded an aggregate gain of approximately $1.4 million related to this transaction, of which $0.4 million was contingent consideration. During 2013, Tanos also sold certain non-operated oil and gas properties for $2.9 million and recorded a gain of $1.4 million.

On May 10, 2013, Black Diamond entered into a purchase and sale agreement with a third party to sell certain of its Wyoming oil and gas properties with an estimated net book value of $39.8 million for $33.0 million, before customary adjustments. As a result, Black Diamond recorded a loss on the sale of $6.8 million. This transaction closed on June 4, 2013.

During 2013, BlueStone entered into an agreement with a third party to sell its remaining interest in certain properties in the Mossy Grove Prospect in Walker and Madison Counties located in East Texas. Total cash consideration received by BlueStone was approximately $117.9 million, which exceeded the net book value of the properties sold by $89.5 million. The transaction closed on July 31, 2013.

On May 1, 2012, MEMP and WildHorse jointly acquired operating and 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 $112.1 million. These properties are located primarily in Polk County, Texas and Lincoln and Claiborne Parishes, Louisiana. During the year ended December 31, 2012, approximately $22.1 million of revenue and $9.2 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, MEMP 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 MEMP’s 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 $147.9 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 net 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 statement of operations related to the Menemsha Acquisition subsequent to the closing date.

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

The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2012 (in thousands) as though the Undisclosed Seller Acquisition, Goodrich Acquisition, and Menemsha Acquisition had been completed on January 1, 2011. The unaudited pro forma financial information was derived from our historical combined statements of operations 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.

During 2012, we also acquired certain interests in oil and gas properties through several individually immaterial acquisitions for an aggregate purchase price of $10.2 million.

During 2012, certain of our subsidiaries sold certain interests in oil and gas properties for an aggregate $3.3 million. Losses of approximately $0.1 million were recognized related to these divestures.

On July 11, 2012, the previous owners 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 previous owners 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.

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.

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).

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		Observable		Unobservable
	Market		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	845,759	$	—	$	845,759
Interest rate derivatives		—		1,305		—		1,305
Total assets	$	—	$	847,064	$	—	$	847,064

Liabilities:
Commodity derivatives	$	—	$	71,639	$	—	$	71,639
Interest rate derivatives		—		3,289		—		3,289
Total liabilities	$	—	$	74,928	$	—	$	74,928

	Fair Value Measurements at December 31, 2013 Using
	Quoted Prices in		Significant Other		Significant
	Active		Observable		Unobservable
	Market		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	105,054	$	—	$	105,054
Interest rate derivatives		—		884		—		884
Total assets	$	—	$	105,938	$	—	$	105,938

Liabilities:
Commodity derivatives	$	—	$	58,234	$	—	$	58,234
Interest rate derivatives		—		5,590		—		5,590
Total liabilities	$	—	$	63,824	$	—	$	63,824

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:

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 agreements are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. At December 31, 2014, MEMP had net derivative assets of $517.1 million. After taking into effect netting arrangements, MEMP had counterparty exposure of $309.8 million related to its derivative instruments of which $109.7 million was with a single counterparty. Had certain counterparties failed completely to perform according to the terms of their existing contracts, MEMP would have the right to offset $207.3 million against amounts outstanding under its revolving credit facility at December 31, 2014. At December 31, 2014, MRD had derivative assets of $255.0 million. After taking into effect netting arrangements, MRD had counterparty exposure of $155.8 million related to derivative instruments. Had certain counterparties failed completely to perform according to the terms of their existing contracts, MRD would have the right to offset $99.2 million against amounts outstanding under its revolving credit facility at December 31, 2014. See Note 8 for additional information regarding our revolving credit facilities.

We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, put options, costless collars, call spreads and basis swaps) to manage exposure to commodity price volatility. We recognize all derivative instruments at fair value; however, certain of our put option derivative instruments have a deferred premium, which reduces the asset. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement. At settlement, if the applicable index price is below the strike price of the put, the Company receives the difference between the strike price and the applicable index price multiplied by the contract volumes less the premium. If the applicable index price settles at or above the strike price of the put, the Company pays only the premium at settlement. During the year ended December 31, 2014, MRD restructured a portion of its commodity derivative portfolio by terminating “in the money” natural gas collars settling in 2015 and entering into natural gas swaps. The cash settlement receipts of $6.1 million from the termination of the collars were utilized to enhance the fixed price portion of the natural gas swaps.

We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub and regional indices such as NGPL TXOK, TETCO STX, TGT Z1, and Houston Ship Channel in proximity to our 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 MRD Segment had the following open commodity positions:

	2015			2016			2017			2018
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		3,700,000			2,570,000			1,770,000			2,900,000
Weighted-average fixed price	$	4.15		$	4.09		$	4.24		$	4.27

Collar contracts:
Average Monthly Volume (MMBtu)		130,000			1,100,000			1,050,000			—
Weighted-average floor price	$	4.00		$	4.00		$	4.00		$	—
Weighted-average ceiling price	$	4.64		$	4.71		$	5.06		$	—

Natural gas put option contracts:
Average Monthly Volume (MMBtu)		3,000,000			4,100,000			3,450,000			2,850,000
Weighted-average fixed price	$	3.75		$	3.75		$	3.75		$	3.75
Weighted-average deferred premium	$	(0.33	)	$	(0.36	)	$	(0.35	)	$	(0.35	)

TGT Z1 basis swaps:
Average Monthly Volume (MMBtu)		1,730,000			220,000			200,000			—
Spread - Henry Hub	$	(0.09	)	$	(0.08	)	$	(0.08	)	$	—

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		46,500			8,500			28,000			31,625
Weighted-average fixed price	$	91.67		$	84.80		$	84.70		$	84.50

Collar contracts:
Average Monthly Volume (Bbls)		2,000			27,000			—			—
Weighted-average floor price	$	85.00		$	80.00		$	—		$	—
Weighted-average ceiling price	$	101.35		$	99.70		$	—		$	—

Put option contracts:
Average Monthly Volume (Bbls)		26,000			—			—			—
Weighted-average fixed price	$	85.00		$	—		$	—		$	—
Weighted-average deferred premium	$	(3.80	)	$	—		$	—		$	—

NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		151,000			185,658			—			—
Weighted-average fixed price	$	41.61		$	34.06		$	—		$	—

At December 31, 2014, the MEMP Segment 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		$	—	$	—	$	—

The MEMP Segment basis swaps included in the table above is 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 - Henry Hub	$	(0.11	)	$	(0.06	)	$	(0.05	)	$	—

HSC basis swaps:
Average Monthly Volume (MMBtu)		150,000			135,000			115,000			115,000
Spread - Henry Hub	$	(0.08	)	$	0.07		$	0.14		$	0.15

CIG basis swaps:
Average Monthly Volume (MMBtu)		210,000			—			—			—
Spread - Henry Hub	$	(0.25	)	$	—		$	—		$	—

TETCO STX basis swaps:
Average Monthly Volume (MMBtu)		300,000			270,000			—			—
Spread - Henry Hub	$	(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	)	$	—		$	—

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 agreements to fixed interest rates. 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:

On July 1, 2014, we elected to terminate the interest rate swaps associated with the MRD credit facility and in the aggregate paid our counterparties approximately $0.7 million. WildHorse Resources novated the interest rate swaps to MRD in connection with the closing of our initial public offering.

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 affiliates, to our derivative contracts are lenders under our collective credit agreements.

		Asset Derivatives						Liability Derivatives
Type	Balance Sheet Location	2014			2013			2014			2013
		(In thousands)
Commodity contracts	Short-term derivative instruments	$	378,908		$	21,759		$	38,852		$	19,739
Interest rate swaps	Short-term derivative instruments		—			845			3,289			3,287
Gross fair value			378,908			22,604			42,141			23,026
Netting arrangements	Short-term derivative instruments		(38,852	)		(13,315	)		(38,852	)		(13,315	)
Net recorded fair value	Short-term derivative instruments	$	340,056		$	9,289		$	3,289		$	9,711

Commodity contracts	Long-term derivative instruments	$	466,851		$	83,295		$	32,787		$	38,495
Interest rate swaps	Long-term derivative instruments		1,305			39			—			2,303
Gross fair value			468,156			83,334			32,787			40,798
Netting arrangements	Long-term derivative instruments		(32,787	)		(34,718	)		(32,787	)		(34,718	)
Net recorded fair value	Long-term derivative instruments	$	435,369		$	48,616		$	—		$	6,080

All gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations since derivative instruments are not designated as hedging instruments for accounting and financial reporting purposes. The following table details the gains and losses related to derivative instruments for the years ending December 31, 2014, 2013, and 2012:

Asset retirement obligations primarily relate to our 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:

The components of the restricted investment balance are as follows at December 31, 2014 and 2013:

The following table presents our consolidated debt obligations at the dates indicated. The MEMP Segment debt included in the table below is nonrecourse to the Company.

Credit facilities tied to borrowing bases are common throughout the oil and gas industry. Each of the revolving credit facilities borrowing base is subject to redetermination on at least a semi-annual basis primarily based on estimated proved reserves. The borrowing base for MRD’s and MEMP’s revolving credit facility was the following at the date indicated:

On June 18, 2014, we, as borrower, and certain of our 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.

We are permitted to borrow under the revolving credit facility in an amount up to the lesser of (i) the face amount of our revolving credit facility, (ii) the borrowing base or (iii) the aggregate elected commitments. The revolving credit facility is reserve-based, and thus our borrowing base is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base is subject to redetermination on 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 our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. In addition, we may, subject to certain conditions, increase our aggregate elected commitments in an amount not to exceed the then effective borrowing base on or following a scheduled redetermination of our borrowing base once before the next scheduled redetermination date.

Borrowings under the revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 80% of the total value of our oil and natural gas properties, and all of our equity interests in any future guarantor subsidiaries and all of our other assets including personal property. Additionally, borrowings bear interest, at our option, at either (i) the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the total commitment usage. The unused portion of the total commitments is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to our total commitments usage.

The revolving credit facility requires maintenance of a ratio of Consolidated EBITDAX to Consolidated Net Interest Expense (as each term is determined under the MRD 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 the revolving credit facility, which we refer to as the current ratio, of not less than 1.0 to 1.0.

Additionally, the 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 our production and prepay certain indebtedness.

Events of default under the revolving credit facility include, but are not limited to, failure to make payments when due, breach of any covenant continuing beyond the applicable 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 our business.

On July 10, 2014, MRD completed a private placement of $600.0 million aggregate principal amount of 5.875% senior unsecured notes (the “MRD Senior Notes”) at par. The MRD Senior Notes will mature on July 1, 2022. Interest on the MRD Senior Notes will accrue from July 10, 2014 and will be payable semiannually on January 1 and July 1 of each year, commencing on January 1, 2015. The MRD Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing subsidiaries (subject to customary release provisions). The MRD Senior Notes and the guarantees of the MRD Senior Notes will rank equally with our and the guarantors’ existing and future senior indebtedness, will be effectively junior to all of our and the guarantors’ existing and future secured indebtedness (to the extent of the value of the assets securing such indebtedness), and senior in right of payment to all of our and the guarantors’ subordinated indebtedness. The MRD Senior Notes will be structurally subordinated to the indebtedness and other liabilities of our non-guarantor subsidiaries, including MEMP and its subsidiaries and MEMP GP.

The MRD Senior Notes are governed by an indenture dated as of July 10, 2014. The MRD Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any, to the date of redemption. The Company may also be required to repurchase the MRD 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 MRD Senior Notes receive an investment grade rating from both of two specified ratings agencies. MEMP and its subsidiaries are not subject to these covenants. 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 the Company or the guarantors, all outstanding MRD 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 MRD Senior Notes may declare all the MRD Senior Notes to be due and payable immediately.

On December 18, 2013, MRD LLC and its wholly-owned subsidiary Memorial Resource Finance Corp. (“MRD Finance Corp.” and, together with MRD LLC, the “MRD Issuers”) completed a private placement of $350.0 million in aggregate principal amount of the PIK notes. The PIK notes were issued at 98% of par with a maturity date of December 15, 2018. Net proceeds from the private offering were used: (i) to repay all indebtedness then outstanding under MRD LLC’s then-existing revolving credit facility, (ii) to establish a cash reserve of $50.0 million for the payment of interest on the PIK notes, (iii) to pay a $210.0 million distribution to the Funds, and (iv) for general company purposes. Interest on the PIK notes was payable semi-annually in arrears on June 15 and December 15 of each year, commencing on June 15, 2014.

A redemption notice was delivered to the PIK notes trustee on June 16, 2014, which specified a redemption date of July 16, 2014 at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption. In connection with the closing of our initial public offering, we assumed the obligations of MRD LLC under the PIK notes indenture and the related debt security agreement. We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our 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. An extinguishment loss of $23.6 million was recognized related to the redemption of the PIK notes.

On April 3, 2013, WildHorse Resources entered into an amended and restated credit agreement. This revolving credit facility provided for aggregate maximum credit amounts at any time of $1.0 billion, consisting of borrowings and letters of credit and had an initial borrowing base of $300.0 million. This revolving credit facility was due to mature on April 13, 2018. The borrowing base was subject to redetermination on at least a semi-annual basis. Borrowings under the revolving credit facility were to be secured by liens on substantially all of WildHorse Resources’ properties, but in any event, not less than 80% of the total value of the WildHorse Resources’ oil and natural gas properties.

On June 13, 2013, WildHorse Resources entered into a $325.0 million second lien term loan agreement that was due to mature on December 13, 2018. Borrowings bore interest, at the borrower’s option, at either: (i) the Alternative Base Rate (as defined within each credit facility) plus 5.25% per annum or (ii) the applicable LIBOR plus 6.25% per annum. Borrowings under the second lien term loan agreement were to be secured by second-priority liens on substantially all of WildHorse Resources’ properties, but in any event, not less than 80% of the total value of the WildHorse Resources’ oil and natural gas properties. The priority of the security interests in the collateral and related creditors’ rights was set forth in an intercreditor agreement. The second lien term loan agreement contained customary affirmative and negative covenants, restrictive provisions and events of default.

On June 13, 2013, WildHorse Resources borrowed $325.0 million under its second lien term loan agreement and used such borrowings to reduce outstanding indebtedness under its revolving credit facility and to pay a onetime special $225.0 million distribution to MRD LLC. This $225.0 million distribution was subsequently distributed to the Funds.

In connection with the closing of our initial public offering, the WildHorse Resources’ revolving credit facility and second lien term loan were repaid in full and terminated. An extinguishment loss of $13.7 million was recognized related to the termination of the revolving credit facility and second lien term loan.

Memorial Production Operating LLC (“OLLC”), a wholly-owned subsidiary of MEMP, is a party to a $2.0 billion revolving credit facility, which is guaranteed by MEMP and all of its current and future subsidiaries (other than certain immaterial subsidiaries).

Borrowings under the revolving credit facility are secured by liens on substantially all of MEMP’s properties, but in any event, not less than 80% of the total value of MEMP’s oil and natural gas properties, and all of MEMP’s equity interests in OLLC and any future guarantor subsidiaries (other than San Pedro Bay Pipeline Company) and all of MEMP’s other assets including personal property. Additionally, borrowings under the revolving credit facility bear interest, at MEMP’s option, at: (i) the Alternative 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 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 (or, if lower, the reduced commitment amount that has been elected) will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.

On April 17, 2013, May 23, 2013 and October 10, 2013, MEMP and its wholly-owned subsidiary Memorial Production Finance Corporation (“Finance Corp.” and, together with MEMP, the “MEMP Issuers”) completed a private placement of $300.0 million, $100.0 million and $300.0 million, respectively, of their 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 all of the MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2021 Senior Notes, and certain immaterial subsidiaries). The 2021 Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes are governed by an indenture. The 2021 Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The MEMP 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 MEMP Issuers, all outstanding 2021 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2021 Senior Notes may declare all the 2021 Senior Notes to be due and payable immediately.

On July 17, 2014, the MEMP Issuers completed a private placement of $500.0 million aggregate principal amount of 6.875% senior unsecured notes (the “2022 Senior Notes”). The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2022 Senior Notes, and certain immaterial subsidiaries). The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year, commencing on February 1, 2015. The indenture governing the 2022 Notes, dated as July 17, 2014, 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 MEMP 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.

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

	For the Year Ended December 31,
	2014			2013			2012
MRD Segment:
MRD revolving credit facility		1.99	%	n/a			n/a
WildHorse Resources revolver terminated June 2014		4.04	%		2.30	%		3.00	%
WildHorse Resources second lien terminated June 2014		6.44	%		7.60	%	n/a
Black Diamond terminated November 2013	n/a				3.97	%		3.62	%
MEMP Segment:
MEMP revolving credit facility		2.67	%		3.25	%		2.74	%
WHT revolver terminated March 2013	n/a				2.29	%		2.60	%
Tanos revolver terminated April 2013	n/a				3.10	%		2.31	%
REO revolving credit facility terminated December 2012	n/a			n/a				3.40	%
Stanolind revolver paid off by MEMP October 2013	n/a				3.52	%		3.76	%
Boaz revolver terminated October 2013	n/a				2.97	%		3.12	%
Crown revolver terminated October 2013	n/a				3.38	%		4.20	%
MRD LLC revolver terminated December 2013	n/a				3.17	%		4.11	%
Classic revolving credit facility terminated November 2012	n/a			n/a				4.50	%
Propel Energy revolver paid off by MEMP October 2013	n/a				3.08	%		3.28	%

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

The Company’s authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the year ended December 31, 2014:

See Note 11 for additional information regarding restricted common shares that were granted in connection with our initial public offering. Restricted shares of common stock are participating securities and considered issued and outstanding on the grant date of restricted stock award.

In December 2014, the board of directors (“Board”) of the Company authorized the repurchase of up to $50.0 million of the Company’s outstanding common stock from time to time on the open market, through block trades or otherwise and are subject to market conditions, as well as corporate, regulatory, and other considerations. During the year ended December 31, 2014, 123,797 shares of common stock were repurchased and retired for a total cost of approximately $2.2 million.

Subsequent event. MRD repurchased 2,764,887 shares of common stock under our repurchase program for an aggregate price of $47.8 million through March 16, 2015. MRD has retired all of the shares of common stock repurchased and the shares of common stock are no longer issued or outstanding.

Our amended and restated certificate of incorporation authorizes our Board, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50,000,000 shares of preferred stock. There are no shares of preferred stock issued and outstanding as of December 31, 2014.

We do not anticipate declaring or providing any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain all future earnings, if any, for use in the operation of our business and to fund future growth. The decision whether to pay dividends in the future will be made by our Board in light of conditions then existing, including factors such as our financial condition, earnings, available cash, business opportunities, legal requirements, restrictions in our debt agreements, and other contracts and other factors our Board deems relevant.

Noncontrolling interests is the portion of equity ownership in the Company’s consolidated subsidiaries not attributable to the Company and primarily consists of the equity interests held by: (i) the limited partners of MEMP, including the subordinated units held by MRD Holdco, that converted to common units in February 2015, and (ii) a third party investor in the San Pedro Bay Pipeline Company. Prior to our initial public offering, certain current or former key employees of certain of MRD LLC’s subsidiaries also held equity interests in those subsidiaries.

Distributions paid to the limited partners of MEMP primarily represent the quarterly cash distributions paid to MEMP’s unitholders, excluding those paid to MRD LLC. Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings.

In December 2012, MEMP sold 11,975,000 if its common units in an underwritten equity offering, which generated net cash proceeds of $194.1 million. The net proceeds from this equity offering partially funded MEMP’s December 2012 acquisition.

On March 25, 2013, MEMP sold 9,775,000 of its common units in an underwritten equity offering, which generated net cash proceeds of $171.8 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering partially funded MEMP’s acquisition of all of the outstanding equity interests in WHT.

On October 8, 2013, MEMP sold 16,675,000 of its common units in an underwritten equity offering, which generated net cash proceeds of approximately $318.3 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering were used to repay a portion of outstanding borrowings under MEMP’s revolving credit facility.

On July 15, 2014, MEMP sold 9,890,000 common units in an underwritten equity offering, which generated net proceeds of approximately $220.0 million after deducting offering expenses. The net proceeds from the equity offering were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility.

On September 9, 2014, MEMP sold 14,950,000 common units in an underwritten equity offering, which generated net proceeds of approximately $321.3 million after deducting underwriting discounts and offering expenses. The net proceeds from the equity offering were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility.

In December 2014, the board of directors of MEMP GP authorized the repurchase of up to $150.0 million of MEMP’s outstanding common units from time to time on the open market, through block trades or otherwise and are subject to market conditions, as well as corporate, regulatory, and other considerations. During the year ended December 31, 2014, 899,912 common units were repurchased and retired for a total cost of approximately $12.9 million.

Subsequent event. MEMP repurchased 1,909,583 common units under its repurchase program for an aggregate price of $28.5 million through February 1, 2015. MEMP has retired all common units repurchased and the common units are no longer issued or outstanding.

On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to MRD LLC and all incentive units held were forfeited. See Note 12 for further information.

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.

On November 1, 2013, MRD LLC purchased the noncontrolling interests in Black Diamond, Classic GP and Classic and all incentive units were forfeited. See Note 12 for further information.

In connection with our initial public offering, certain former management members of WildHorse Resources contributed their 0.1% membership interest in WildHorse Resources as well as their incentive units in exchange for shares of our common stock and cash consideration of $30.0 million. The difference between the carrying amount of the noncontrolling interest of $0.4 million and the fair value of the consideration paid of $3.3 million was recognized directly in stockholders’ equity as additional paid in capital. See Note 12 for further information.

The following sets forth the calculation of earnings (loss) per share, or EPS, for the period indicated (in thousands, except per share amounts):

Our supplemental basic and diluted EPS includes earnings allocated to both previous owners and MRD LLC members for the period presented due to common control considerations. The following sets forth the calculation of our supplemental EPS, for the period indicated (in thousands, except per share amounts):

In June 2014, our Board adopted the Memorial Resource Development Corp. 2014 Long Term Incentive Plan (“MRD LTIP”) for the employees of the Company and the Board. The MRD LTIP became effective upon filing of a registration statement on Form S-8 with the SEC on June 18, 2014. The MRD LTIP provides for potential grants of stock options, stock appreciation rights, restricted stock awards, restricted stock units, bonus stock, dividend equivalents, performance awards, annual incentive awards, and other stock-based awards. The MRD LTIP initially limits the number of common shares that may be delivered pursuant to awards under the plan up to 19,250,000 common shares. Common shares that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The MRD LTIP will be administered by our Board or a committee thereof.

In connection with our initial public offering, our Board approved an aggregate award of 1,052,633 shares of restricted stock under the MRD LTIP to certain of our key employees, including each of our executive officers. These restricted stock awards will vest ratably on a four-year annual vesting schedule from the date of the grant and are subject to restrictions on transferability and customary forfeiture provisions. An award of 5,263 shares of restricted stock was also granted to each of our independent directors. These restricted stock awards will vest one year from the date of the grant and are also subject to restrictions on transferability and customary forfeiture provisions.

Award recipients are entitled to all the rights of absolute ownership of the restricted common shares, including the right to vote those shares and to receive dividends thereon if, as, and when declared by our Board. The term “restricted common share” represents a time-vested share. Such awards are non-vested until the required service period expires.

The following table summarizes information regarding restricted common share awards granted under the MRD LTIP for the periods presented:

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):

The unrecognized compensation cost associated with restricted common share awards was an aggregate $17.3 million at December 31, 2014. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 3.43 years.

In December 2011, the Memorial Production Partners GP LLC Long-Term Incentive Plan (“MEMP LTIP”) was adopted for employees, officers, consultants and directors of MEMP GP and any of its affiliates who perform services for MEMP. The MEMP LTIP consists of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The MEMP 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 restricted common units awarded are subject to restrictions on transferability, customary forfeiture provisions and graded vesting provisions. One-third of each award generally vests on the first, second, and third anniversaries of the date of grant. Award recipients have all the rights of a unitholder in MEMP with respect to the restricted common units, including the right to receive distributions thereon if and when distributions are made by MEMP to its unitholders (except with respect to the fourth quarter 2011 distribution that was paid in February 2012). The term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires.

The following table summarizes information regarding restricted common unit awards granted under the MEMP LTIP for the periods presented:

The unrecognized compensation cost associated with restricted common unit awards was $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 noncontrolling interests as presented on our statements of consolidated and combined cash flows.

Each of the governing documents of BlueStone, Tanos, WildHorse Resources, Classic, Black Diamond and MRD LLC previously provided for the issuance of incentive units. 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.

BlueStone, Tanos, WildHorse Resources, Classic, Black Diamond and MRD LLC each 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 ranging from 10% to 31.5% when declared, but only after cumulative distribution thresholds (“payouts”) had been achieved. Payouts were generally triggered after the recovery of specified members’ capital contributions plus a rate of return. In connection with MEMP’s initial public offering in December 2011, BlueStone’s Special Tier and Tier I unit holders vested in their respective awards. Tier I unit holders became eligible to participate in 16.5% of any future distributions made by BlueStone.

Vesting of the incentive units was generally dependent upon an explicit service period, a fundamental change as defined in the respective governing document, and achievement of payout. All incentive units not vested were forfeited if an employee was no longer employed. All incentive units were forfeited if a holder resigned whether the incentive units were vested or not. If the payouts had not yet occurred, then all incentive units, whether or not vested, were forfeited automatically (unless extended).

On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to MRD LLC and all incentive units held were forfeited. Compensation expense of approximately $5.8 million was recorded by Tanos and recognized as a component of general and administrative expense during the year ended December 31, 2013.

On November 1, 2013, MRD LLC purchased the noncontrolling interests in Black Diamond, Classic GP and Classic and all incentive units were forfeited. Compensation expense of approximately $12.6 million was recorded by Black Diamond, Classic GP and Classic in the aggregate during November 2013.

Compensation expense of approximately $1.0 million and $20.7 million was recorded by BlueStone and recognized as a component of incentive unit compensation expense during the year ended December 31, 2014 and 2013, respectively. No compensation expense was recorded at December 31, 2012.

In connection with the PIK notes issued in December 2013, a special distribution of $10.0 million to holders of WildHorse’s Tier 1 incentive units was deemed probable of occurring. This amount was recognized as compensation expense in December 2013 with a corresponding amount in accrued liabilities on our balance sheet at December 31, 2013 as payment was not made until January 2, 2014.

In connection with the our initial public offering, certain former management members of WildHorse Resources contributed their 0.1% membership interest in WildHorse Resources as well as their incentive units in exchange for 42,334,323 shares of our common stock and cash consideration of $30.0 million. The portion of the total consideration related to acquiring the 0.1% membership interest was accounted for as the acquisition of noncontrolling interests. The difference between the carrying amount of the noncontrolling interest of $0.4 million and the fair value of the consideration paid of $3.3 million was recognized directly in stockholders’ equity as additional paid in capital. Compensation expense of approximately $831.1 million was recognized as a component of incentive unit compensation expense during the year ended December 31, 2014 related to the incentive units, of which approximately $26.7 million was paid in cash and the remaining $804.4 million related to the issuance of our common stock.

MRD LLC incentive units were originally granted in June 2012 and February 2013. In connection with our initial public offering and the related restructuring transactions, these incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. MRD Holdco’s governing documents authorize the issuance of 1,000 incentive units, of which 930 incentive units were granted in an exchange for the cancelled MRD LLC awards (the “Exchanged Incentive Units”).

The holders of the Exchanged Incentive Units are eligible to participate in 9.3% of any future distributions made by MRD Holdco. The payment likelihood was deemed probable as a result of our initial public offering and the reasonable expectation that MRD Holdco will monetize the shares of our common stock it owns over an estimated three year period as market conditions permit. During 2014, we recognized $111.5 million of compensation expense offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $105.5 million as of December 31, 2014 will be recognized over the remaining expected service period of 2.41 years.

Subsequent to our initial public offering, MRD Holdco granted the remaining 70 incentive units to certain key employees (the “Subsequent Incentive Units”). The holders of the Subsequent Incentive Units are eligible to participate in 0.7% of any future distributions made by MRD Holdco once payout associated with these incentive units has been achieved. The payment likelihood was deemed probable at December 31, 2014 as a result of our initial public offering and the reasonable expectation that MRD Holdco will monetize the shares of our common stock it owns over an estimated three year period as market conditions permit. During 2014, we recognized $0.4 million of compensation expense and the unrecognized compensation expense of approximately $1.7 million as of December 31, 2014 will be recognized over the remaining expected service period of 2.41 years.

The fair value of the Exchanged and Subsequent Incentive Units will be remeasured on a quarterly basis until all payments have been made. The settlement obligation rests with MRD Holdco. Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense will be allocated to us in future periods offset by capital contributions. As such, these awards are not dilutive to our stockholders.

The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions:

Amounts due to (due from) MRD Holdco 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.

Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Upon the acquisition of the Petrohawk properties WildHorse Resources immediately sold a net profits interest of 6.25% for all producing well bores and the right to participate in a 3.125% net profits interest in non-producing wellbores for the subject area for $19.5 million, or $19.1 million after adjustments. Upon the acquisition of the Clayton Williams properties, WildHorse Resources immediately sold a net profits interest of 23.5% for all producing wellbores and the right to participate in a 10.0% net profits interest in non-producing wellbores for the subject area for $19.8 million, or $19.9 million after adjustments. No gain or loss was recorded from these two transactions.

The net profits agreements for these transactions provided for a fixed fee of $20,000 per month for overhead and management in lieu of COPAS (Council of Petroleum Accountants Societies) billings. The net profits agreements did not provide for an overhead adjustment factor for this monthly charge, as suggested by COPAS. Quarterly net payments were made to NGPCIF for its net profits interest in the Petrohawk and Clayton Williams acquisitions. The net payments included credits for revenue receipts which were offset with production costs, capital expenditures and the management fee and were adjusted for any acquisition settlements received or paid and any other miscellaneous adjustments. As required by such agreements, WildHorse Resources could not collect funds owed by NGPCIF to WildHorse Resources, but WildHorse Resources could net amounts due from future quarterly payments.

As a result of these transactions, WildHorse Resources paid NGPCIF a total of $2.6 million and $2.3 million during 2013 and 2012, respectively. NGPCIF owed WildHorse Resources $0.2 million at December 31, 2013.

WildHorse Resources repurchased the net profits interests discussed above from NGPCIF on February 28, 2014 for a purchase price of $63.4 million (see Note 1). 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. WildHorse Resources recorded the following net assets (in thousands):

Due to common control considerations, the difference between the purchase price and the net assets acquired are reflected within equity as a deemed distribution to NGP affiliates.

The previous owners sold certain interests in oil and gas properties 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 recognized in the equity statement as a net contribution.

On December 12, 2012, MEMP acquired Rise Energy Operating, Inc. (‘REO”), which owns certain operating interests in producing and non-producing oil and gas properties offshore Southern California (the “Beta Properties”), 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 MEMP’s revolving credit facility and the net proceeds generated from its December 12, 2012 public offering of common units. 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. MEMP recorded the following net assets (in thousands):

An affiliate of REO collected a management fee for providing administrative services to REO. These administrative services included accounting, business development, finance, legal, information technology, insurance, government regulations, communications, regulatory, environmental and human resources services. REO incurred and paid management fees of $1.6 million during the year ended December 31, 2012. These management fees are presented as a component of general and administrative costs and expenses in the accompanying statements of operations.

On October 1, 2013, MEMP 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), of which approximately $507.1 million was received by certain affiliates of NGP. We refer to this transaction as the “Cinco Group acquisition.” The Cinco Group acquisition was funded with borrowings under MEMP’s revolving credit facility. The Cinco Group acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method.

On March 10, 2014, BlueStone sold certain interests in oil and gas properties in McMullen, Webb, Zapata, and Hidalgo Counties located in South Texas to BlueStone Natural Resources II, LLC, an NGP controlled entity. Total cash consideration received by BlueStone was approximately $1.2 million, which exceeded the net book value of the properties sold by $0.5 million. Due to common control considerations, the $0.5 million was recognized in the equity statement as a contribution.

On March 28, 2014, MRD Royalty acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from Propel Energy for $3.3 million.

On June 18, 2014, in connection with our initial public offering and the related restructuring transactions (see Note 1), WHR Management Company was sold by WildHorse Resources to an affiliate of the Funds for net book value. The net book value of the assets sold was as follows (in thousands):

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.

In connection with the closing of our initial public offering, we entered into a registration rights agreement with MRD Holdco and former management members of WildHorse Resources, Jay Graham (“Graham”) and Anthony Bahr (“Bahr”). Pursuant to the registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances.

In connection with the closing of our initial public offering, we entered into a voting agreement with MRD Holdco, WHR Incentive LLC, a limited liability company beneficially owned by Messrs. Bahr and Graham, and certain former management members of WildHorse Resources, who contributed their ownership of WildHorse Resources to us in the restructuring transactions. Among other things, the voting agreement provides that those former management members of WildHorse Resources will vote all of their shares of our common stock as directed by MRD Holdco. The voting agreement also prohibits the transfer of any shares of our common stock by the former management members of WildHorse Resources until after the termination of the services agreement described below; provided, however, that the former management members of WildHorse Resources (other than Messrs. Bahr and Graham) may transfer their shares of our common stock after the 180 day lock-up period has expired and these transfer restrictions will not prohibit Messrs. Bahr and Graham from exercising piggyback registration rights under the registration rights agreement described above.

In connection with the closing of our initial public offering, we entered into a services agreement with WildHorse Resources and WHR Management Company, pursuant to which WHR Management Company would provide operating and administrative services to us for twelve months relating to the Terryville Complex. In exchange for such services, we paid a monthly management fee to WHR Management Company of approximately $1.0 million excluding third party COPAS income credits.

Upon the closing of our initial public offering, WHR Management Company became a subsidiary of WildHorse Resources II, LLC, an affiliate of the Company. NGP and certain former management members of WildHorse Resources own WHR II.

WHR II is an independent energy company engaged in the acquisition, exploration, and development of natural gas and crude oil properties. WHR II is a related party and was organized in the State of Delaware on June 3, 2013. A management services agreement was executed on August 8, 2013, where WildHorse Resources provided general, administrative and employee services to WHR II. On August 8, 2013, a management agreement between WildHorse Resources and WHR II was executed where WildHorse was appointed the manager for WHR II with responsibilities included administrative and land services, operator services and financial and accounting services. As operator, WildHorse Resources received operated and non-operated revenues on behalf of WHR II and billed and received joint interest billings. In addition, WildHorse Resources paid for lease operating expenses and drilling costs on behalf of WHR II. On August 8, 2013, an asset and cost sharing agreement between WildHorse Resources and WHR II was executed. As part of the agreement, shared WildHorse Resources costs were allocated between WildHorse Resources and WHR II in accordance with a sharing ratio. The sharing ratio is based on the previous quarter’s capital expenditures and number of operated wells. Company specific costs were billed directly to the appropriate entity. As a result of these agreements, WildHorse Resources received net payments of $4.4 million from WHR II in 2013. WildHorse Resources owed WHR II $2.4 million as of December 31, 2013. These agreements were terminated in connection with our initial public offering.

MEMP entered into transition service agreements with Propel Energy, Stanolind, and Boaz Energy Partners to provide operating and administrative services to MEMP with respect to the acquired properties. The term of these agreements were from October 1, 2013 through February 28, 2014. MEMP paid transition service fees of approximately $0.8 million in the aggregate under these agreements.

Effective March 1, 2012, BlueStone entered into an agreement with CH4 Energy III, LLC, an NGP controlled entity, to sell an undivided 25% interest in certain properties in the Mossy Grove Prospect in Walker and Madison Counties located in East Texas. Total cash consideration received by BlueStone was approximately $7.0 million, which exceeded the net book value of the properties sold by $6.4 million. Due to common control considerations, the $6.4 million was recognized in the equity statement as a contribution. The transaction closed on July 13, 2012.

A company affiliated with one of 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.

Certain of the Cinco Group entities entered into 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 was approximately $0.4 million. There were no fees for the year ended December 31, 2013.

During 2012, the previous owners 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.

On March 17, 2014, WildHorse Resources entered into a gas processing agreement with PennTex North Louisiana, LLC (“PennTex”). PennTex is a joint venture among certain affiliates of NGP in which MRD Holdco owns, through its subsidiary MRD Midstream LLC, a minority interest. Once PennTex’s processing plant becomes operational, it will process natural gas produced from wells located on certain leases owned by us in the state of Louisiana. The agreement has a 15-year primary term, subject to one-year extensions at either party’s election. We will pay PennTex a monthly fee, subject to an annual inflationary escalation, based on volumes of natural gas delivered and processed. Once the plant is declared operational, we will be obligated to pay a minimum processing fee equal to approximately $18.3 million on an annual basis, subject to certain adjustments and conditions. The gas processing agreement requires that the processing plant be operational no later than November 1, 2015.

On November 1, 2011, Classic Hydrocarbons Operating, LLC (“Classic Operating”), which became our wholly-owned subsidiary in connection with the restructuring transactions, and 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.

Our reportable business segments are organized in a manner that reflects how management manages those business activities.

We have two reportable business segments, both of which are engaged in the acquisition, exploration, development and production of oil and natural gas properties. Our reportable business segments are as follows:

We evaluate segment performance based on Adjusted EBITDA. Adjusted EBITDA is defined as net income (loss), plus interest expense; loss on extinguishment of debt; income tax expense; depreciation, depletion and amortization (“DD&A”); impairment of goodwill and long-lived properties; accretion of asset retirement obligations (“AROs”); losses on commodity derivative contracts and cash settlements received; losses on sale of properties; incentive-based compensation expenses; exploration costs; provision for environmental remediation; equity loss from MEMP (MRD Segment only); cash distributions from MEMP (MRD Segment only); acquisition related costs; amortization of investment premium; and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and cash settlements paid; equity income from MEMP (MRD Segment only); gains on sale of assets and other non-routine items.

Financial information presented for the MEMP business segment is derived from the underlying consolidated and combined financial statements of MEMP that are publicly available.

Segment revenues and expenses include intersegment transactions. Our combined totals reflect the elimination of intersegment transactions.

In the MRD Segment’s individual financial statements, investments in the MEMP Segment that are included in the consolidated and combined financial statements are accounted for by the equity method.

The following table presents selected business segment information for the periods indicated (in thousands):

					Other,			Consolidated
					Adjustments &			& Combined
	MRD		MEMP		Eliminations			Totals
Total revenues:
For the Year ended December 31, 2014	$	363,126	$	536,219	$	—		$	899,345
For the Year ended December 31, 2013		201,886		373,137		—			575,023
For the Year ended December 31, 2012		104,072		293,165		(369	)		396,868
Adjusted EBITDA: (1)
For the Year ended December 31, 2014		316,317		337,560		(6,144	)		647,733
For the Year ended December 31, 2013		175,994		244,094		(25,232	)		394,856
For the Year ended December 31, 2012		99,746		211,693		(23,447	)		287,992
Segment assets: (2)
As of December 31, 2014		1,413,768		3,189,760		(9,981	)		4,593,547
As of December 31, 2013		1,033,958		1,849,368		(54,165	)		2,829,161
Total cash expenditures for additions to long-lived assets:
For the Year ended December 31, 2014		487,001		1,382,133		—			1,869,134
For the Year ended December 31, 2013		254,724		213,723		—			468,447
For the Year ended December 31, 2012		188,903		447,782		—			636,685

	For the Year Ended December 31, 2014
							Combined
	MRD			MEMP			Totals
	(In thousands)
Net income (loss)	$	(764,333	)	$	115,614		$	(648,719	)
Interest expense, net		50,283			83,550			133,833
Loss on extinguishment of debt		37,248			—			37,248
Income tax expense (benefit)		102,392			(1,421	)		100,971
DD&A		128,238			185,955			314,193
Impairment of proved oil and natural gas properties		24,576			407,540			432,116
Accretion of AROs		533			5,773			6,306
(Gain) loss on commodity derivative instruments		(257,734	)		(492,254	)		(749,988	)
Cash settlements received (paid) on commodity derivative instruments		9,166			13,522			22,688
(Gain) loss on sale of properties		3,057			—			3,057
Acquisition related costs		2,305			4,363			6,668
Incentive-based compensation expense		946,753			7,874			954,627
Exploration costs		13,853			2,750			16,603
Provision for environmental remediation		—			2,852			2,852
Loss on office lease		1,180			1,442			2,622
Non-cash equity (income) loss from MEMP		12,656			—			12,656
Cash distributions from MEMP		6,144			—			6,144
Adjusted EBITDA	$	316,317		$	337,560		$	653,877

	For the Year Ended December 31, 2013
							Combined
	MRD			MEMP			Totals
				(In thousands)
Net income (loss)	$	91,390		$	61,005		$	152,395
Interest expense, net		24,948			44,302			69,250
Income tax expense (benefit)		1,311			308			1,619
DD&A		70,903			113,814			184,717
Impairment of proved oil and natural gas properties		2,528			4,072			6,600
Accretion of AROs		593			4,988			5,581
(Gain) loss on commodity derivative instruments		(3,161	)		(26,133	)		(29,294	)
Cash settlements received (paid) on commodity derivative instruments		8,481			23,638			32,119
(Gain) loss on sale of properties		(82,773	)		(2,848	)		(85,621	)
Acquisition related costs		1,584			6,729			8,313
Incentive-based compensation expense		34,997			11,840			46,837
Non-cash compensation expense		—			1,057			1,057
Exploration costs		1,034			1,322			2,356
Non-cash equity (income) loss from MEMP		(1,847	)		—			(1,847	)
Cash distributions from MEMP		26,006			—			26,006
Adjusted EBITDA	$	175,994		$	244,094		$	420,088

	For the Year Ended December 31, 2012
							Combined
	MRD			MEMP			Totals
				(In thousands)
Net income (loss)	$	8,810		$	23,067		$	31,877
Interest expense, net		8,283			24,955			33,238
Income tax expense (benefit)		(1	)		108			107
DD&A		37,048			101,624			138,672
Impairment of proved oil and natural gas properties		5,877			22,994			28,871
Accretion of AROs		551			4,458			5,009
(Gain) loss on commodity derivative instruments		(10,500	)		(24,405	)		(34,905	)
Cash settlements received (paid) on commodity derivative instruments		20,740			53,559			74,299
(Gain) loss on sale of properties		(2	)		(9,759	)		(9,761	)
Acquisition related costs		403			4,135			4,538
Incentive-based compensation expense		9,510			1,423			10,933
Amortization of investment premium		—			194			194
Exploration costs		460			9,340			9,800
Non-cash equity (income) loss from MEMP		(696	)		—			(696	)
Cash distributions from MEMP		19,263			—			19,263
Adjusted EBITDA	$	99,746		$	211,693		$	311,439

The following table presents a reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) for each of the periods indicated (in thousands):

	For the Year Ended December 31,
	2014			2013			2012
Total Reportable Segments' Adjusted EBITDA	$	653,877		$	420,088		$	311,439
Adjustments to reconcile Adjusted EBITDA to net income (loss):
Interest expense, net		(133,833	)		(69,250	)		(33,238	)
Loss on extinguishment of debt		(37,248	)		—			—
Income tax benefit (expense)		(100,971	)		(1,619	)		(107	)
DD&A		(314,193	)		(184,717	)		(138,672	)
Impairment of proved oil and natural gas properties		(432,116	)		(6,600	)		(28,871	)
Accretion of AROs		(6,306	)		(5,581	)		(5,009	)
Gains (losses) on commodity derivative instruments		749,988			29,294			34,905
Cash settlements paid (received) on commodity derivative instruments		(22,688	)		(32,119	)		(74,299	)
Gain (loss) on sale of properties		(3,057	)		85,621			9,761
Acquisition related costs		(6,668	)		(8,313	)		(4,538	)
Incentive-based compensation expense		(954,627	)		(46,837	)		(10,933	)
Non-cash compensation expense		—			(1,057	)		—
Exploration costs		(16,603	)		(2,356	)		(9,800	)
Amortization of investment premium		—			—			(194	)
Cash distributions from MEMP		(6,144	)		(26,006	)		(19,263	)
Provision for environmental remediation		(2,852	)		—			—
Loss on office lease		(2,622	)		—			—
Other non-cash equity (income) loss		—			784			(4,184	)
Net income (loss)	$	(636,063	)	$	151,332		$	26,997

Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated (in thousands):

	For the Year Ended December 31, 2014
	MRD			MEMP			Other, Adjustments & Eliminations		Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	363,114		$	531,853		$	—	$	894,967
Other revenues		12			4,366			—		4,378
Total revenues		363,126			536,219			—		899,345

Costs and expenses:
Lease operating		17,570			143,733			—		161,303
Pipeline operating		—			2,068			—		2,068
Exploration		13,853			2,750			—		16,603
Production and ad valorem taxes		12,610			33,141			—		45,751
Depreciation, depletion, and amortization		128,238			185,955			—		314,193
Impairment of proved oil and natural gas properties		24,576			407,540			—		432,116
Incentive unit compensation expense		943,949			—			—		943,949
General and administrative		38,549			49,124			—		87,673
Accretion of asset retirement obligations		533			5,773			—		6,306
(Gain) loss on commodity derivative instruments		(257,734	)		(492,254	)		—		(749,988	)
(Gain) loss on sale of properties		3,057			—			—		3,057
Other, net		(1	)		(11	)		—		(12	)
Total costs and expenses		925,200			337,819			—		1,263,019
Operating income (loss)		(562,074	)		198,400			—		(363,674	)
Other income (expense):
Interest expense, net		(50,283	)		(83,550	)		—		(133,833	)
Loss on extinguishment of debt		(37,248	)		—			—		(37,248	)
Earnings from equity investments		(12,656	)		—			12,656		—
Other, net		320			(657	)		—		(337	)
Total other income (expense)		(99,867	)		(84,207	)		12,656		(171,418	)
Income (loss) before income taxes		(661,941	)		114,193			12,656		(535,092	)
Income tax benefit (expense)		(102,392	)		1,421			—		(100,971	)
Net income (loss)	$	(764,333	)	$	115,614		$	12,656	$	(636,063	)

	For the Year Ended December 31, 2013
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	201,886		$	370,062		$	—		$	571,948
Other revenues		—			3,075			—			3,075
Total revenues		201,886			373,137			—			575,023

Costs and expenses:
Lease operating		17,315			96,433			(108	)		113,640
Pipeline operating		—			1,835			—			1,835
Exploration		1,034			1,322			—			2,356
Production and ad valorem taxes		8,699			18,447			—			27,146
Depreciation, depletion, and amortization		70,903			113,814			—			184,717
Impairment of proved oil and natural gas properties		2,528			4,072			—			6,600
Incentive unit compensation expense		34,997			8,282			—			43,279
General and administrative		35,309			46,665			105			82,079
Accretion of asset retirement obligations		593			4,988			—			5,581
(Gain) loss on commodity derivative instruments		(3,161	)		(26,133	)		—			(29,294	)
(Gain) loss on sale of properties		(82,773	)		(2,848	)		—			(85,621	)
Other, net		2			647			—			649
Total costs and expenses		85,446			267,524			(3	)		352,967
Operating income (loss)		116,440			105,613			3			222,056
Other income (expense):
Interest expense, net		(24,948	)		(44,302	)		—			(69,250	)
Earnings from equity investments		1,066			—			(1,066	)		—
Other, net		143			2			—			145
Total other income (expense)		(23,739	)		(44,300	)		(1,066	)		(69,105	)
Income before income taxes		92,701			61,313			(1,063	)		152,951
Income tax benefit (expense)		(1,311	)		(308	)		—			(1,619	)
Net income (loss)	$	91,390		$	61,005		$	(1,063	)	$	151,332

	For the Year Ended December 31, 2012
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	103,728		$	289,912		$	(9	)	$	393,631
Other revenues		344			3,253			(360	)		3,237
Total revenues		104,072			293,165			(369	)		396,868

Costs and expenses:
Lease operating		16,582			87,972			(800	)		103,754
Pipeline operating		—			2,114			—			2,114
Exploration		460			9,340			—			9,800
Production and ad valorem taxes		8,270			15,354			—			23,624
Depreciation, depletion, and amortization		37,048			101,624			—			138,672
Impairment of proved oil and natural gas properties		5,877			22,994			—			28,871
Incentive unit compensation expense		9,510			—			—			9,510
General and administrative		24,134			35,112			431			59,677
Accretion of asset retirement obligations		551			4,458			—			5,009
(Gain) loss on commodity derivative instruments		(10,500	)		(24,405	)		—			(34,905	)
(Gain) loss on sale of properties		(2	)		(9,759	)		—			(9,761	)
Other, net		464			38			—			502
Total costs and expenses		92,394			244,842			(369	)		336,867
Operating income (loss)		11,678			48,323			—			60,001
Other income (expense):
Interest expense, net		(8,283	)		(24,955	)		—			(33,238	)
Amortization of investment premium		—			(194	)		—			(194	)
Earnings from equity investments		4,880			—			(4,880	)		—
Other, net		534			1			—			535
Total other income (expense)		(2,869	)		(25,148	)		(4,880	)		(32,897	)
Income before income taxes		8,809			23,175			(4,880	)		27,104
Income tax benefit (expense)		1			(108	)		—			(107	)
Net income (loss)	$	8,810		$	23,067		$	(4,880	)	$	26,997

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

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:

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	$	109		$	37
Accrued liabilities		—			5
Other		342			(42	)
Deferred current income tax assets:	$	451		$	—

Deferred current income tax liabilities:
Unrealized hedging transactions	$	(52,328	)		—
Other		(52	)		(382	)
Deferred current income tax liabilities:	$	(52,380	)	$	(382	)

Deferred noncurrent income tax assets:
Net operating loss carryforward	$	28,043		$	2,350
Asset retirement obligation		5,757			971
Other		3,224			1
Net deferred tax valuation allowance		(2,634	)		(2,896	)
Deferred noncurrent income tax assets:	$	34,390		$	426

Deferred noncurrent income tax liabilities:
Property, plant and equipment	$	(80,198	)	$	(3,318	)
Unrealized hedging transactions		(48,929	)		(275	)
Other		(280	)		61
Deferred noncurrent income tax liabilities:	$	(129,407	)	$	(3,532	)

Net current deferred income tax assets (liabilities)	$	(51,929	)	$	(382	)
Net noncurrent deferred income tax assets (liabilities)	$	(95,017	)	$	(3,106	)

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 Company has no unrecognized tax benefits for the years ended December 31, 2014, 2013 or 2012.

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

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

As of December 31, 2014, the Company has available, to reduce future taxable income, a United States net operating loss carryforwards (NOLs) of approximately $74.3 million before consideration of any valuation allowance which expires in the years 2027 thru 2035. A portion of these net operating loss carryforwards are subject to the ownership change limitation provisions of Section 382 of the Internal Revenue Code (IRC). The Company also has various net state NOL carryforwards of approximately $65.0 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.

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 when environmental remediation efforts are probable and the costs can be reasonably estimated. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals.

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

At December 31, 2014 and 2013, $2.1 million and $0.6 million, respectively, of our environmental reserves were classified as current liabilities in accrued liabilities.

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.

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.

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):

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):

At December 31, 2014, MEMP had a CO₂ purchase commitment with a third party that was assumed in its Wyoming Acquisition. The table below outlines MEMP’s purchase commitment under the contract for the remainder of 2014 and annually thereafter (in thousands):

In 2012, WildHorse Resources contracted with Regency Field Services LLC (the “Gatherer”) to expand their Dubach processing plant by up to 70 MMcf per day among other facility and infrastructure improvements. In 2013, WildHorse Resources contracted with the Gatherer to build a new high pressure pipeline from the dedicated area to the Gatherer’s Dubberly processing plant in Webster Parish, LA amongst other pipeline and infrastructure improvements. The Gatherer is entitled to receive a payback demand fee from us and other third parties equal to 110% of the infrastructure improvement costs. Effective February 1, 2014, the payback demand fee is equal to the monthly demand quantity (192,950 MMBtu per day) times $0.275 per MMBtu. In addition, for each MMBtu gathered in excess of the demand quantity, we are obligated to pay a payback demand fee of $0.275 per MMBtu. The monthly demand quantity escalated to 249,700 MMBtu per day until payout effective January 1, 2015.

WildHorse Resources’ minimum commitments to the Gatherer, before other owner contributions, as of December 31, 2014 were as follows (in thousands):

Classic Operating entered into a gas gathering agreement and water disposal agreement with Classic Pipeline.

On March 17, 2014, WildHorse Resources entered into a gas processing agreement with PennTex. See Note 13 for additional information.

We have leases for offshore Southern California pipeline right-of-way use as well as office space for our corporate headquarters and operating regions. We also lease equipment and incur surface rentals related to our business operations. For the years ended December 31, 2014, 2013, and 2012 we recognized $10.8 million, $8.3 million, and $5.0 million of rent expense, respectively.

Amounts shown in the following table represent minimum lease payment obligations and sublease rental income under non-cancelable operating leases with a remaining term in excess of one year:

MRD 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. MRD makes matching contributions of 100% of employee contributions that does not exceed 6% of compensation. Employees are immediately vested in these matching contributions. This plan became effective on January 1, 2012. The 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 MRD subsidiary (Beta Operating) 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. This plan was terminated December 31, 2013. 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 the each of the years ended December 31, 2013 and 2012, respectively.

WildHorse, Tanos, BlueStone, Classic and Black Diamond also sponsored defined contribution plans for the benefit their eligible employees. Matching employer contributions of approximately $0.2 million, $0.5 million and $0.6 million were made to these other plans in 2014, 2013 and 2012, respectively.

Crown and Stanolind also made matching contributions to defined contribution plans for the benefit of their eligible employees. Matching employer contributions of approximately $0.1 million were made to these plans in both 2013 and 2012. Such contributions to these plans are included in general and administrative expenses in the accompanying combined statements of operations.

The Company owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under the MRD Senior Notes outstanding are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries on a senior unsecured basis. Subsidiaries with noncontrolling interests and certain de minimis subsidiaries are non-guarantors.

The following condensed consolidating financial information presents the financial information of the Company on a unconsolidated stand-alone basis and its combined guarantor and combined non-guarantor subsidiaries as of and for the period indicated. Such financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities.

	December 31, 2014
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2,241	$	3,762	$	970	$	(1,015	)	$	5,958
Accounts receivable - trade		5,995		44,952		83,346		(2,717	)		131,576
Accounts receivable - affiliates		10,047		—		28		(10,075	)		—
Short-term derivative instruments		131,471		—		208,585		—			340,056
Prepaid expenses and other current assets		5,833		7,993		14,201		—			28,027
Total current assets		155,587		56,707		307,130		(13,807	)		505,617
Property and equipment, net		16,601		1,050,722		2,470,333		—			3,537,656
Long-term derivative instruments		123,567		—		311,802		—			435,369
Investments in subsidiaries		1,139,792		—		—		(1,139,792	)		—
Other long-term assets		14,124		5,660		100,521		(5,400	)		114,905
Total assets	$	1,449,671	$	1,113,089	$	3,189,786	$	(1,158,999	)	$	4,593,547

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	6,245	$	107,068	$	114,584	$	(3,125	)	$	224,772
Accounts payable - affiliates		—		3,638		6,409		(9,423	)		624
Revenues payable		—		27,242		30,110		—			57,352
Short-term derivative instruments		—		—		3,289		—			3,289
Total current liabilities		6,245		137,948		154,392		(12,548	)		286,037
Long-term debt		783,000		—		1,595,413		—			2,378,413
Asset retirement obligations		—		9,830		112,701		—			122,531
Deferred tax liabilities		69,431		—		30,986		(5,400	)		95,017
Other long-term liabilities		8,585		—		—		—			8,585
Total liabilities		867,261		147,778		1,893,492		(17,948	)		2,890,583
Equity:
Equity		582,410		965,311		1,290,734		(2,256,045	)		582,410
Noncontrolling interests		—		—		5,560		1,114,994			1,120,554
Total equity		582,410		965,311		1,296,294		(1,141,051	)		1,702,964
Total liabilities and equity	$	1,449,671	$	1,113,089	$	3,189,786	$	(1,158,999	)	$	4,593,547

	December 31, 2013
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Combined & Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	48,619	$	29,102	$	—		$	77,721
Restricted cash		—		35,000		—		—			35,000
Accounts receivable - trade		—		49,655		39,459		(392	)		88,722
Accounts receivable - affiliates		—		8,905		1,532		(5,785	)		4,652
Short-term derivative instruments		—		1,688		7,601		—			9,289
Prepaid expenses and other current assets		—		7,783		11,730		—			19,513
Total current assets		—		151,650		89,424		(6,177	)		234,897
Property and equipment, net		—		785,914		1,633,790		—			2,419,704
Long-term derivative instruments		—		5,960		42,656		—			48,616
Investments in subsidiaries		—		288,760		—		(288,760	)		—
Other long-term assets		—		35,137		90,807		—			125,944
Total assets	$	—		1,267,421		1,856,677		(294,937	)		2,829,161

LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	—	$	61,865	$	57,392	$	(393	)	$	118,864
Accounts payable - affiliates		—		7,481		1,017		(6,523	)		1,975
Revenues payable		—		36,307		19,784		—			56,091
Short-term derivative instruments		—		1,715		7,996		—			9,711
Total current liabilities		—		107,368		86,189		(6,916	)		186,641
Long-term debt		—		871,150		792,067		—			1,663,217
Asset retirement obligations		—		9,612		102,067		—			111,679
Long-term derivative instruments		—		205		5,875		—			6,080
Deferred tax liabilities		—		—		1,151		1,955			3,106
Other long-term liabilities		—		306		1,955		(1,955	)		306
Total liabilities		—		988,641		989,304		(6,916	)		1,971,029
Equity:
Equity		—		277,517		855,768		(855,768	)		277,517
Noncontrolling interests		—		1,263		11,605		567,747			580,615
Total equity		—		278,780		867,373		(288,021	)		858,132
Total liabilities and equity	$	—	$	1,267,421	$	1,856,677	$	(294,937	)	$	2,829,161

	December 31, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Combined & Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—		$	363,114		$	531,853		$	—	$	894,967
Other revenues		5			7			4,366			—		4,378
Total revenues		5			363,121			536,219			—		899,345

Costs and expenses:
Lease operating		—			17,570			143,733			—		161,303
Pipeline operating		—			—			2,068			—		2,068
Exploration		—			13,853			2,750			—		16,603
Production and ad valorem taxes		—			12,610			33,141			—		45,751
Depreciation, depletion and amortization		1,133			127,105			185,955			—		314,193
Impairment of proved oil and natural gas properties		—			24,576			407,540			—		432,116
Incentive unit compensation expense		111,866			831,060			1,023			—		943,949
General and administrative		13,232			25,277			49,164			—		87,673
Accretion of asset retirement obligations		—			533			5,773			—		6,306
(Gain) loss on commodity derivatives		(277,129	)		19,395			(492,254	)		—		(749,988	)
(Gain) loss on sale of properties		—			3,167			(110	)		—		3,057
Other, net		—			—			(12	)		—		(12	)
Total costs and expenses		(150,898	)		1,075,146			338,771			—		1,263,019
Operating income (loss)		150,903			(712,025	)		197,448			—		(363,674	)

Other income (expense):
Interest expense, net		(19,532	)		(30,751	)		(83,550	)		—		(133,833	)
Debt extinguishment costs		(23,562	)		(13,686	)		—			—		(37,248	)
Equity earnings from subsidiaries		(809,017	)		—			—			809,017		—
Other, net		—			319			(656	)		—		(337	)
Total other income (expense)		(852,111	)		(44,118	)		(84,206	)		809,017		(171,418	)
Income before income taxes		(701,208	)		(756,143	)		113,242			809,017		(535,092	)
Income tax benefit (expense)		(83,373	)		(19,028	)		1,430			—		(100,971	)
Net income (loss)		(784,581	)		(775,171	)		114,672			809,017		(636,063	)
Net income (loss) attributable to noncontrolling interest		—			—			32			126,756		126,788
Net income (loss) attributable to Memorial Resource Development Corp.	$	(784,581	)	$	(775,171	)	$	114,640		$	682,261	$	(762,851	)

	December 31, 2013
	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Combined & Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—	$	184,757		$	387,191		$	—		$	571,948
Other revenues		—		—			3,075			—			3,075
Total revenues		—		184,757			390,266			—			575,023

Costs and expenses:
Lease operating		—		14,710			98,930			—			113,640
Pipeline operating		—		—			1,835			—			1,835
Exploration		—		1,034			1,322			—			2,356
Production and ad valorem taxes		—		7,869			19,277			—			27,146
Depreciation, depletion and amortization		—		61,990			122,727			—			184,717
Impairment of proved oil and natural gas properties		—		128			6,472			—			6,600
Incentive unit compensation expense		—		14,353			28,926			—			43,279
General and administrative		—		31,674			50,405			—			82,079
Accretion of asset retirement obligations		—		516			5,065			—			5,581
(Gain) loss on commodity derivatives		—		(3,179	)		(26,115	)		—			(29,294	)
(Gain) loss on sale of properties		—		6,776			(92,397	)		—			(85,621	)
Other, net		—		—			649			—			649
Total costs and expenses		—		135,871			217,096			—			352,967
Operating income (loss)		—		48,886			173,170			—			222,056

Other income (expense):
Interest expense, net		—		(24,895	)		(44,355	)		—			(69,250	)
Equity earnings from subsidiaries		—		71,222			—			(71,222	)		—
Other, net		—		141			4			—			145
Total other income (expense)		—		46,468			(44,351	)		(71,222	)		(69,105	)
Income before income taxes		—		95,354			128,819			(71,222	)		152,951
Income tax benefit (expense)		—		(164	)		(1,455	)		—			(1,619	)
Net income (loss)		—		95,190			127,364			(71,222	)		151,332
Net income (loss) attributable to noncontrolling interest		—		—			267			49,563			49,830
Net income (loss) attributable to Memorial Resource Development Corp.	$	—	$	95,190		$	127,097		$	(120,785.00	)	$	101,502

	December 31, 2012
	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Combined & Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—	$	100,242		$	293,389		$	—		$	393,631
Other revenues		—		—			3,237			—			3,237
Total revenues		—		100,242			296,626			—			396,868

Costs and expenses:
Lease operating		—		14,656			89,529			(431	)		103,754
Pipeline operating		—		—			2,114			—			2,114
Exploration		—		466			9,334			—			9,800
Production and ad valorem taxes		—		8,021			15,603			—			23,624
Depreciation, depletion and amortization		—		34,843			103,829			—			138,672
Impairment of proved oil and natural gas properties		—		4,250			24,621			—			28,871
Incentive unit compensation expense		—		9,510			—			—			9,510
General and administrative		—		19,525			39,721			431			59,677
Accretion of asset retirement obligations		—		487			4,522			—			5,009
(Gain) loss on commodity derivatives		—		(10,500	)		(24,405	)		—			(34,905	)
(Gain) loss on sale of properties		—		(2	)		(9,759	)		—			(9,761	)
Other, net		—		459			43			—			502
Total costs and expenses		—		81,715			255,152			—			336,867
Operating income (loss)		—		18,527			41,474			—			60,001

Other income (expense):
Interest expense, net		—		(8,164	)		(25,074	)		—			(33,238	)
Equity earnings from subsidiaries		—		(16,331	)		—			16,331			—
Other, net		—		456			(115	)		—			341
Total other income (expense)		—		(24,039	)		(25,189	)		16,331			(32,897	)
Income before income taxes		—		(5,512	)		16,285			16,331			27,104
Income tax benefit (expense)		—		—			(107	)		—			(107	)
Net income (loss)		—		(5,512	)		16,178			16,331			26,997
Net income (loss) attributable to noncontrolling interest		—		—			104			(2,805	)		(2,701	)
Net income (loss) attributable to Memorial Resource Development Corp.	$	—	$	(5,512.00	)	$	16,074		$	19,136		$	29,698

	December 31, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Combined & Consolidated
	(In thousands)
Net cash provided by (used in) operating activities	$	(72,612	)	$	297,490		$	251,393		$	—		$	476,271

Cash flows from investing activities:
Acquisitions of oil and natural gas properties		—			(93,909	)		(1,083,761	)		—			(1,177,670	)
Additions to oil and gas properties		—			(376,123	)		(298,273	)		—			(674,396	)
Additions to restricted investments		—			—			(3,976	)		—			(3,976	)
Additions to other property and equipment		(15,980	)		(989	)		(98	)		—			(17,067	)
Investment in subsidiaries		(696,489	)		—			—			696,489			—
Distribution from subsidiaries		15,140			74,424			—			(89,564	)		—
Change in restricted cash		—			49,946			—			—			49,946
Deposits for property acquisitions		—			(215	)		—			—			(215	)
Proceeds from the sale of oil and gas properties		—			—			6,700			—			6,700
Other		—			—			(301	)		—			(301	)
Net cash used in investing activities		(697,329	)		(346,866	)		(1,379,709	)		606,925			(1,816,979	)

Cash flows from financing activities:
Advances on revolving credit facilities		1,174,000			126,800			1,446,000			—			2,746,800
Payments on revolving credit facilities		(991,000	)		(329,900	)		(1,137,000	)		—			(2,457,900	)
Proceeds from the issuances of senior notes		600,000			—			492,425			—			1,092,425
Redemption of senior notes		(351,808	)		—			—			—			(351,808	)
Redemption of second lien credit facility		—			(328,282	)		—			—			(328,282	)
Deferred financing costs		(18,779	)		(61	)		(11,494	)		—			(30,334	)
Proceeds from initial public offering		408,500			—			—			—			408,500
Costs incurred in conjunction with initial public offering		(28,373	)		—			—			—			(28,373	)
Proceeds from MEMP public offering		—			—			553,288			—			553,288
Costs incurred in conjunction with MEMP public offering		—			—			(12,510	)		—			(12,510	)
MRD equity repurchases		(161	)		—			—			—			(161	)
MEMP equity repurchases		—			—			(11,531	)		—			(11,531	)
Restricted MEMP units returned to plan		—			—			(1,012	)		—			(1,012	)
Purchase of additional interests in subsidiaries		(3,292	)		—			—			—			(3,292	)
Capital contributions		—			686,623			9,866			(696,489	)		—
Contributions from NGP affiliates related to sale of properties		—			—			1,165			—			1,165
Distribution to equity owners		—			(15,000	)		(222,633	)		237,633			—
Distributions to MRD Holdco		(17,207	)		(39,520	)		(3,076	)					(59,803	)
Distributions to noncontrolling interests		—			—			—			(149,084	)		(149,084	)
Distribution to NGP affiliates related to purchase of assets		—			(63,389	)		(3,304	)		—			(66,693	)
Distribution to NGP affiliates related to sale of assets, net of cash received		—			(32,770	)		—			—			(32,770	)
Other		302			18			—						320
Net cash provided by financing activities		772,182			4,519			1,100,184			(607,940	)		1,268,945
Net change in cash and cash equivalents		2,241			(44,857	)		(28,132	)		(1,015	)		(71,763	)
Cash and cash equivalents, beginning of period		—			48,619			29,102			—			77,721
Cash and cash equivalents, end of period	$	2,241		$	3,762		$	970		$	(1,015	)	$	5,958

	December 31, 2013
	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Combined & Consolidated
	(In thousands)
Net cash provided by (used in) operating activities	$	—	$	93,864		$	183,959		$	—		$	277,823

Cash flows from investing activities:
Acquisitions of oil and natural gas properties		—		(67,098	)		(38,664	)		—			(105,762	)
Additions to oil and gas properties		—		(164,850	)		(195,165	)		—			(360,015	)
Additions to restricted investments		—		—			(5,361	)		—			(5,361	)
Additions to other property and equipment		—		(2,432	)		(238	)		—			(2,670	)
Investment in subsidiaries		—		(93,433	)		—			93,433			—
Distribution from subsidiaries		—		273,694			—			(273,694	)		—
Change in restricted cash		—		(49,347	)		—			—			(49,347	)
Proceeds from the sale of oil and gas properties		—		33,152			122,560						155,712
Net cash used in investing activities		—		(70,314	)		(116,868	)		(180,261	)		(367,443	)

Cash flows from financing activities:
Advances on revolving credit facilities		—		174,400			958,355			—			1,132,755
Payments on revolving credit facilities		—		(200,500	)		(1,565,537	)		—			(1,766,037	)
Proceeds from the issuances of senior notes		—		343,000			688,563			—			1,031,563
Borrowings under second lien credit facility		—		325,000			—			—			325,000
Deferred financing costs		—		(20,250	)		(20,925	)		—			(41,175	)
Proceeds from MEMP public offering		—		—			511,204			—			511,204
Costs incurred in conjunction with MEMP public offering		—		—			(21,066	)		—			(21,066	)
Proceeds from changes in ownership interests in MEMP		—		135,012			—			—			135,012
Purchase of additional interests in subsidiaries		—		(15,135	)		—			—			(15,135	)
Capital contributions		—		—			93,433			(93,433	)		—
Contributions from previous owners		—		—			1,214			—			1,214
Contributions from NGP affiliates related to sale of properties		—		—			2,013			—			2,013
Distributions to the Funds		—		(732,362	)		—			—			(732,362	)
Distribution to equity owners		—		—			(351,777	)		351,777			—
Distributions to noncontrolling interests		—		—			—			(78,083	)		(78,083	)
Distribution to NGP affiliates related to purchase of assets		—		—			(355,494	)		—			(355,494	)
Distributions made by previous owners		—		(2,590	)		(1,415	)		—			(4,005	)
Equity repurchases		—		—			—			—			—
Cash retained by previous owners		—		—			(7,909	)		—			(7,909	)
Other		—		(129	)		584			—			455
Net cash provided by financing activities		—		6,446			(68,757	)		180,261			117,950
Net change in cash and cash equivalents		—		29,996			(1,666	)		—			28,330
Cash and cash equivalents, beginning of period		—		18,623			30,768			—			49,391
Cash and cash equivalents, end of period	$	—	$	48,619		$	29,102		$	—		$	77,721

	December 31, 2012
	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidation
	(In thousands)
Net cash provided by (used in) operating activities	$	—	$	56,443		$	183,961		$	—		$	240,404

Cash flows from investing activities:
Acquisitions of oil and natural gas properties		—		(83,055	)		(277,623	)		—			(360,678	)
Additions to oil and gas properties		—		(85,431	)		(187,903	)		—			(273,334	)
Additions to restricted investments		—		—			(4,599	)		—			(4,599	)
Additions to other property and equipment		—		(926	)		(1,748	)		—			(2,674	)
Investment in subsidiaries		—		(718	)		—			718			—
Distribution from subsidiaries		—		22,979			—			(22,979	)		—
Change in restricted cash		—		(3	)		—			—			(3	)
Proceeds from the sale of oil and gas properties		—		—			34,521			—			34,521
Other		—		—			29			—			29
Net cash used in investing activities		—		(147,154	)		(437,323	)		(22,261	)		(606,738	)

Cash flows from financing activities:
Advances on revolving credit facilities		—		122,950			496,500			—			619,450
Payments on revolving credit facilities		—		(24,750	)		(226,819	)		—			(251,569	)
Deferred financing costs		—		(1,109	)		(2,392	)		—			(3,501	)
Capital contributions		—		—			718			(718	)		—
Contributions from previous owners		—		—			44,072			—			44,072
Contributions from NGP affiliates related to sale of properties		—		—			45,158			—			45,158
Proceeds from MEMP public offering		—		—			202,573			—			202,573
Costs incurred in conjunction with MEMP public offering		—		—			(8,268	)		—			(8,268	)
Distributions to equity owners		—		—			(38,187	)		38,187			—
Distribution to NGP affiliates related to purchase of assets		—		—			(242,174	)		—			(242,174	)
Distributions to noncontrolling interests		—		—			—			(15,208	)		(15,208	)
Distributions made by previous owners		—		(2,282	)		(26,490	)		—			(28,772	)
Net cash provided by financing activities		—		94,809			244,691			22,261			361,761
Net change in cash and cash equivalents		—		4,098			(8,671	)		—			(4,573	)
Cash and cash equivalents, beginning of period		—		14,525			39,439			—			53,964
Cash and cash equivalents, end of period	$	—	$	18,623		$	30,768		$	—		$	49,391

The following tables present selected quarterly financial data for the periods indicated. Earnings per share are computed independently for each of the quarters presented and the sum of the quarterly earnings per share may not necessarily equal the total for the year. As discussed in Note 4 and Note 12, we recorded oil and natural gas property impairments and incentive unit compensation expense, respectively, during 2014, which impacted the comparability between the periods presented below.

	First Quarter			Second Quarter			Third Quarter		Fourth Quarter
For the Year Ended December 31, 2014	(In thousands, except per share amounts)
Revenues	$	190,828		$	236,564		$	245,493	$	226,460
Operating income (loss)		10,605			(993,256	)		174,201		444,776
Net income (loss)		(23,516	)		(1,053,443	)		112,037		328,859
Net income (loss) attributable to noncontrolling interest		(31,888	)		(105,094	)		102,109		161,661
Net income (loss) attributable to Memorial Resource Development Corp.		8,372			(948,349	)		9,928		167,198
Net income (loss) allocated to members		6,947			13,358			—		—
Net income (loss) allocated to previous owners		1,425			—			—		—
Net income (loss) available to common stockholders	n/a				(961,707	)		9,928		167,198
Basic earnings per share	n/a				(5.00	)		0.05		0.87
Diluted earnings per share	n/a				(5.00	)		0.05		0.87

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.

	For the Year Ended December 31,
	2014			2013			2012
	(In thousands)
MRD Segment:
Evaluated oil and natural gas properties	$	1,268,873		$	897,511		$	742,404
Unevaluated oil and natural gas properties		48,229			44,453			24,629
Accumulated depletion, depreciation, and amortization		(276,837	)		(160,620	)		(122,712	)
Subtotal	$	1,040,265		$	781,344		$	644,321
MEMP Segment:
Evaluated oil and natural gas properties (1)	$	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)		(1,057,398	)		(462,742	)		(345,579	)
Subtotal	$	2,457,937		$	1,622,472		$	1,516,602
Consolidated:
Evaluated oil and natural gas properties (1)	$	4,598,211		$	2,974,855		$	2,591,861
Support equipment and facilities		185,997			5,910			5,760
Unevaluated oil and natural gas properties		48,229			46,413			31,593
Accumulated depletion, depreciation, and amortization (1)		(1,334,235	)		(623,362	)		(468,291	)
Total	$	3,498,202		$	2,403,816		$	2,160,923

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:

	For the Year Ended December 31,
	2014		2013		2012
	(In thousands)
MRD Segment:
Property acquisition costs, proved	$	74,490	$	56,108	$	87,857
Property acquisition costs, unproved		24,310		19,975		5,293
Exploration and extension well costs		209,532		13,313		212
Development		181,026		191,350		99,028
Subtotal	$	489,358	$	280,746	$	192,390
MEMP Segment:
Property acquisition costs, proved	$	983,796	$	37,786	$	278,246
Exploration and extension well costs		—		—		42,430
Development (1)		306,751		164,920		99,395
Subtotal	$	1,290,547	$	202,706	$	420,071
Consolidated:
Property acquisition costs, proved	$	1,058,286	$	93,894	$	366,103
Property acquisition costs, unproved		24,310		19,975		5,293
Exploration and extension well costs		209,532		13,313		42,642
Development (1)		487,777		356,270		198,423
Total	$	1,779,905	$	483,452	$	612,461

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 Company’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.

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 MEMP engaged NSAI and Ryder Scott to audit our internally prepared reserves estimates for all 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:

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

	For the Year Ended December 31, 2014
	Oil (MBbls)			Gas (MMcf)			NGLs (MBbls)			Equivalent (MMcfe)
Proved developed and undeveloped reserves:
Beginning of the year		50,459			1,409,393			71,422			2,140,683
Extensions and discoveries		2,674			196,250			10,587			275,815
Purchase of minerals in place		69,364			35,222			23,598			592,996
Production		(4,042	)		(105,295	)		(4,363	)		(155,718	)
Sales of minerals in place		(623	)		(10,815	)		(950	)		(20,253	)
Revision of previous estimates		(5,659	)		215,801			11,773			252,467
End of year (1)		112,173			1,740,556			112,067			3,085,990

Proved developed reserves:
Beginning of year		25,667			651,345			29,863			984,535
End of year		58,431			772,578			55,463			1,455,934

Proved undeveloped reserves:
Beginning of year		24,792			758,048			41,559			1,156,148
End of year		53,742			967,978			56,604			1,630,056

	For the Year Ended December 31, 2013
	Oil (MBbls)			Gas (MMcf)			NGLs (MBbls)			Equivalent (MMcfe)
Proved developed and undeveloped reserves:
Beginning of the year		51,042			1,343,818			70,818			2,074,982
Extensions and discoveries		7,449			190,744			10,065			295,832
Purchase of minerals in place		330			48,109			1,275			57,737
Production		(2,429	)		(70,016	)		(3,089	)		(103,122	)
Sales of minerals in place		(599	)		(14,137	)		(1,573	)		(27,169	)
Revision of previous estimates		(5,334	)		(89,125	)		(6,074	)		(157,577	)
End of year (1)		50,459			1,409,393			71,422			2,140,683

Proved developed reserves:
Beginning of year		27,597			622,381			28,268			957,573
End of year		25,667			651,345			29,863			984,535

Proved undeveloped reserves:
Beginning of year		23,445			721,437			42,550			1,117,409
End of year		24,792			758,048			41,559			1,156,148

	For the Year Ended December 31, 2012
	Oil (MBbls)			Gas (MMcf)			NGLs (MBbls)			Equivalent (MMcfe)
Proved developed and undeveloped reserves:
Beginning of the year		37,984			1,509,086			68,076			2,145,454
Extensions and discoveries		8,190			61,888			3,831			134,010
Purchase of minerals in place		12,436			141,732			8,974			270,190
Production		(1,888	)		(53,875	)		(1,643	)		(75,056	)
Sales of minerals in place		(4,218	)		(4,942	)		—			(30,250	)
Revision of previous estimates		(1,462	)		(310,071	)		(8,420	)		(369,366	)
End of year (1)		51,042			1,343,818			70,818			2,074,982

Proved developed reserves:
Beginning of year		21,439			604,988			17,659			839,577
End of year		27,597			622,381			28,268			957,573

Proved undeveloped reserves:
Beginning of year		16,545			904,098			50,417			1,305,877
End of year		23,445			721,437			42,550			1,117,409

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

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.

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:

	For the Year Ended December 31,
	2014			2013			2012
	(In thousands)
Beginning of year	$	3,077,065		$	2,910,511		$	2,885,485
Sale of oil and natural gas produced, net of production costs		(687,717	)		(430,964	)		(267,339	)
Purchase of minerals in place		1,558,759			74,337			474,337
Sale of minerals in place		(47,791	)		(54,091	)		(154,963	)
Extensions and discoveries		697,931			437,427			393,102
Changes in income taxes, net		(1,058,815	)		—			1,947
Changes in prices and costs		196,530			(85,731	)		(733,962	)
Previously estimated development costs incurred		480,466			261,787			130,750
Net changes in future development costs		(201,177	)		(17,514	)		(68,471	)
Revisions of previous quantities		665,089			(327,926	)		(267,375	)
Accretion of discount		307,707			287,535			288,743
Change in production rates and other		(265,905	)		21,694			228,257
End of year	$	4,722,142		$	3,077,065		$	2,910,511

		Page No.
Report of Independent Registered Public Accounting Firm		F-2
Consolidated and Combined Balance Sheets as of December 31, 2014 and 2013		F-3
Statements of Consolidated and Combined Operations for the Years Ended December 31, 2014, 2013 and 2012		F-4
Statements of Consolidated and Combined Cash Flows for the Years Ended December 31, 2014, 2013 and 2012		F-5
Statements of Consolidated and Combined Equity for the Years Ended December 31, 2014, 2013 and 2012		F-6
Notes to Consolidated and Combined Financial Statements
	Note 1 – Organization and Basis of Presentation	F-8
	Note 2 – Summary of Significant Accounting Policies	F-10
	Note 3 – Acquisitions and Divestitures	F-16
	Note 4 – Fair Value Measurements of Financial Instruments	F-20
	Note 5 – Risk Management and Derivative Instruments	F-22
	Note 6 – Asset Retirement Obligations	F-27
	Note 7 – Restricted Investments	F-28
	Note 8 – Long Term Debt	F-28
	Note 9 – Stockholders’ Equity and Noncontrolling Interests	F-33
	Note 10 – Earnings per Share	F-35
	Note 11 – Long-Term Incentive Plans	F-35
	Note 12 – Incentive Units	F-37
	Note 13 – Related Party Transactions	F-39
	Note 14 – Business Segment Data	F-43
	Note 15 – Income Taxes	F-49
	Note 16 – Commitments and Contingencies	F-51
	Note 17 – Defined Contribution Plans	F-53
	Note 18 – Condensed Consolidating Financial Information	F-53
	Note 19 – Quarterly Financial Information (Unaudited)	F-61
	Note 20 – Supplemental Oil and Gas Information (Unaudited)	F-62
	Note 21 – Subsequent Events	F-66

	December 31,
	2014		2013
Accrued capital expenditures	$	80,350	$	48,579
Accrued lease operating expense		16,403		13,240
Accrued general and administrative expenses		8,516		14,485
Accrued ad valorem and production taxes		8,870		3,541
Accrued interest payable		24,797		11,934
Accrued environmental		2,092		577
Accrued current deferred income taxes		51,929		382
Other miscellaneous, including operator advances		6,043		5,392
	$	199,000	$	98,130

	MRD			MEMP			MEMP
	Louisiana			Eagle Ford			Wyoming
	Acquisition			Acquisition			Acquisition
Oil and gas properties	$	72,141		$	168,606		$	930,168
Asset retirement obligations		(271	)		(285	)		(3,980	)
Revenue Payable		—			—			(375	)
Accrued liabilities		—			(250	)		(19,693	)
Total identifiable net assets	$	71,870		$	168,071		$	906,120

Credit Facility	2015			2016			2017
MEMP:
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

	2014		2013
	(In thousands)
BOEM platform abandonment (See Note 16)	$	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

	Years Ending December 31,
	2014			2013			2012
Consolidated & Combined:
Energy Transfer Equity, L.P. and subsidiaries		33	%		35	%		13	%

MRD Segment:
Energy Transfer Equity, L.P. and subsidiaries		85	%		86	%		52	%
Sunoco, Inc. (1)	n/a			n/a				20	%

MEMP Segment:
Sinclair Oil & Gas Company		11	%	n/a			n/a
Phillips 66 (2)		12	%		14	%		12	%
ConocoPhillips	n/a			n/a				13	%

	Louisiana			East Texas			Rockies
	Acquisition			Acquisition			Acquisition
Oil and gas properties	$	68,887		$	9,974		$	20,744
Asset retirement obligation		(1,789	)		(78	)		(1,163	)
Accrued liabilities		-			-			(118	)
Total identifiable net assets	$	67,098		$	9,896		$	19,463


	Undisclosed Seller			Goodrich			Menemsha			Other
	Acquisition			Acquisition			Acquisition			Acquisitions
Oil and gas properties	$	115,633		$	91,187		$	75,114		$	77,764
Prepaid expenses and other current assets		—			425			—			—
Revenues payable		(1,602	)		(875	)		—			—
Asset retirement obligation		(1,592	)		(161	)		(408	)		(4,558	)
Accrued liabilities		(297	)		(153	)		—			—
Total identifiable net assets	$	112,142		$	90,423		$	74,706		$	73,206

	Statements of	For the Years Ended December 31,
	Operations Location	2014			2013			2012
		(In thousands)
Commodity derivative contracts	(Gain) loss on commodity derivatives	$	(749,988	)	$	(29,294	)	$	(34,905	)
Interest rate derivatives	Interest expense, net		145			(239	)		5,582

Balance January 1, 2014	—
Shares of common stock issued in connection with restructuring transactions (Note 1)	171,000,000
Shares of common stock issued in initial public offering (Note 1)	21,500,000
Shares of common stock repurchased and retired	(123,797	)
Restricted common shares issued (Note 11)	1,068,422
Restricted common shares forfeited	(9,211	)
Balance December 31, 2014	193,435,414

	For the Year Ended December 31,
	2014
Numerator:
Net income (loss) available to common stockholders	$	(784,581	)

Denominator:
Weighted average common shares outstanding		192,498

Basic EPS	$	(4.08	)
Diluted EPS (1)	$	(4.08	)

	Number of Shares			Weighted-Average Grant Date Fair Value per Share (1)
Restricted common shares outstanding at January 1, 2014		—		$	—
Granted (2)		1,068,422		$	19.00
Forfeited		(9,211	)	$	19.00
Restricted common units outstanding at December 31, 2014		1,059,211		$	19.00

	Number of Units			Weighted-Average Grant Date Fair Value 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

	Exchanged Incentive Units			Subsequent Incentive Units
Valuation date	12/31/2014			12/31/2014
Dividend yield		0	%		0	%
Expected volatility		39.54	%		39.54	%
Risk-free rate		0.85	%		0.85	%
Expected life (years)		2.41			2.41

Accounts receivable	$	2,274
Oil and natural gas properties, net		40,056
Accrued liabilities		(297	)
Asset retirement obligations		(277	)
Net assets	$	41,756

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

Cash and cash equivalents	$	2,820
Accounts receivable		5,184
Prepaid expenses and other current assets		1,454
Oil and natural gas properties, net		342,759
Long-term derivative instruments, net		(826	)
Other long-term assets		344
Accounts payable		(2,346	)
Revenue payable		(2,910	)
Accrued liabilities		(1,799	)
Short-term derivative instruments, net		(1,828	)
Asset retirement obligations		(9,606	)
Credit facilities		(151,690	)
Net assets	$	181,556

Cash and cash equivalents	$	33,001
Restricted cash		300
Accounts receivable		5,256
Prepaid expenses and other current assets		379
Property, plant and equipment, net		3,410
Other long-term assets		4
Accounts payable		(19,959	)
Accounts payable - affiliates		(17,099	)
Accrued liabilities		(5,061	)
Net assets	$	231

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

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

			Payment or Settlement due by Period
Purchase commitment	Total			2015		2016		2017		2018		2019		Thereafter

CO₂ minimum purchase commitment:
Estimated payment obligation	$	50,495		$	9,608	$	10,179	$	10,151	$	6,995	$	7,060	$	6,502

	Dubach		Dubberly
2015	$	13,671	$	11,393
2016		13,709		11,424
2017		13,671		11,393
2018		12,772		10,643
Total	$	53,823	$	44,853