Exhibit 99.1

ITEM  7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the financial statements and related notes in “Item 8. Financial Statements and Supplementary Data” contained under Exhibit 99.2 of this Current Report. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences are discussed in “Risk Factors” contained in Part I—Item 1A of our 2014 Form 10-K. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Forward-Looking Statements” in the front of this report.

Overview

We are a Delaware corporation, formed by Memorial Resource Development LLC (“MRD LLC”) in January 2014, engaged in the acquisition, exploration, and development of natural gas and oil properties primarily in North Louisiana. MRD LLC, our accounting predecessor, 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 own, acquire, exploit and develop oil and natural gas properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”).

We completed our initial public offering on June 18, 2014. In connection with the closing of our initial public offering, MRD LLC contributed to us substantially all of its assets, comprised of the following, in exchange for shares of our common stock (which were distributed to MRD LLC’s sole member, MRD Holdco LLC (“MRD Holdco”)): (1) 100% of its ownership interests in Classic Hydrocarbons Holdings, L.P. (“Classic”), Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”), Black Diamond Minerals, LLC (“Black Diamond”), Beta Operating Company, LLC (“Beta Operating”), MRD Operating LLC (“MRD Operating”) and Memorial Production Partners GP LLC (“MEMP GP”), which owns a 0.1% general partner interest and 50% of the incentive distribution rights in Memorial Production Partners LP (“MEMP”), and (2) its 99.9% membership interest in WildHorse Resources, LLC (“WildHorse Resources”). In addition, certain former management members of WildHorse Resources contributed to us the remaining 0.1% membership interest in WildHorse Resources, and also exchanged their incentive units in WildHorse Resources, for shares of our common stock and cash consideration. As a result, we are majority-owned by the group consisting of MRD Holdco and certain former management members of WildHorse Resources.

Following the completion of our initial public offering, MRD LLC distributed to MRD Holdco (i) its interests in BlueStone Natural Resources Holdings, LLC (“BlueStone”), MRD Royalty LLC (“MRD Royalty”), MRD Midstream LLC (“MRD Midstream”), Golden Energy Partners LLC (“Golden Energy”) and Classic Pipeline & Gathering, LLC (“Classic Pipeline”), (ii) the MEMP subordinated units (which converted to common units on February 13, 2015); (iii) the remaining cash released from its debt service reserve account in connection with the redemption of the 10.00% /10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”); and (iv) approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014. We also reimbursed MRD LLC for the approximately $17.2 million interest payment that it made on the PIK notes on June 15, 2014, which was distributed to MRD Holdco.

As part of the restructuring transactions, we merged Black Diamond into MRD Operating in connection with the completion of our initial public offering, and MRD LLC was merged into MRD Operating upon the termination of the PIK notes indenture on June 27, 2014. WildHorse Resources merged into MRD Operating in February 2015.

We control MEMP through the ownership of MEMP GP. MEMP is a publicly traded limited partnership engaged in the acquisition, production and development of oil and natural gas properties in the United States. Due to our control of MEMP through the ownership of MEMP GP, we are required to consolidate MEMP for accounting and financial reporting purposes. Although consolidated for accounting and financial reporting, we each have independent capital structures. We will receive cash distributions from MEMP as a result of MEMP GP’s 0.1% general partner interest and incentive distribution rights in MEMP, when declared and paid by MEMP.

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Business Segments

Our reportable business segments are organized in a manner that reflects how management manages those business activities. We evaluate segment performance based on Adjusted EBITDA. The definition and calculation of Adjusted EBITDA and the reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) is included in the notes to our consolidated and combined financial statements found under “Item 8. Financial Statements and Supplementary Data,” contained under Exhibit 99.2 of this Current Report. Adjusted EBITDA (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by our management in evaluating segment performance. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss). Our computation of Adjusted EBITDA may not be comparable to similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

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:

● MRD—reflects the combined operations of the Company, MRD Operating, MRD LLC, WildHorse Resources and its previous owners, Black Diamond, BlueStone, Beta Operating and MEMP GP.

● MEMP—reflects the combined operations of MEMP, its previous owners, and certain historical dropdown transactions that occurred between MEMP and other MRD (or its predecessor) consolidating subsidiaries.

Segment financial information has been retrospectively revised for the following common control transactions between MEMP and MRD or its predecessor for comparability purposes:

● acquisition by MEMP of certain oil and gas properties in East Texas and non-core Louisiana from MRD in exchange for MEMP’s North Louisiana oil and gas properties and approximately $78.0 million in cash in February 2015;

● acquisition by MEMP of all the outstanding membership interests in Tanos Energy, LLC (“Tanos”) for a purchase price of approximately $77.4 million in October 2013;

● acquisition by MEMP of all the outstanding membership interests in Prospect Energy, LLC (“Prospect Energy”) from Black Diamond for a purchase price of approximately $16.3 million in October 2013;

● acquisition by MEMP of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million in October 2013;

● acquisition by MEMP of all the outstanding membership interests in WHT Energy Partners LLC (“WHT”) for a purchase price of approximately $200.0 million in March 2013;

● acquisition by MEMP of certain assets from Classic in East Texas in May 2012 for a purchase price of approximately $27.0 million; and

● acquisition by MEMP of certain assets from Tanos in East Texas in April 2012 for a purchase price of approximately $18.5 million.

The MRD Segment is focused on the acquisition, exploration, and development of natural gas and oil properties primarily in the Cotton Valley formation in North Louisiana. These properties consist primarily of assets with extensive production histories, high drilling success rates, and significant horizontal redevelopment potential. The MRD Segment is focused on maintaining and growing its production and cash flow primarily through the development of its sizeable inventory. The MRD Segment, prior to our initial public offering, included BlueStone, MRD Royalty, MRD Midstream, Golden Energy, Classic Pipeline, the MEMP subordinated units and cash held in a debt service reserve account that had been established when the PIK notes were issued in December 2013.

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The MEMP Segment is engaged in the acquisition, exploitation, development and production of oil and natural gas properties, with assets consisting primarily of producing oil and natural gas properties that are located in Texas, Louisiana, Colorado, Wyoming, and New Mexico and offshore Southern California. Most of the MEMP Segment’s properties are located in large, mature oil and natural gas reservoirs with well-known geologic characteristics and long-lived, predictable production profiles and modest capital requirements. The MEMP Segment is focused on generating stable cash flows to allow MEMP to make quarterly cash distributions to its unitholders and, over time, to increase those quarterly cash distributions.

Outlook

The continuation of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital. Although we cannot predict the occurrence of events or factors that will affect future commodity prices, such as the supply of, and demand for, oil, natural gas, and NGLs, and general domestic or foreign economic conditions and political developments, or the degree to which these prices will be affected, the prices for any oil, natural gas or NGLs that we produce will generally approximate market prices in the geographic region of the production.

Oil prices declined significantly in the second half of 2014 and have continued to drop in early 2015. This decline in oil prices stems in large part from decreased demand due to weak economic activity and increased efficiency, an excess of supply due to sustained high output from North America, and the Organization of Petroleum Exporting Countries failure to reach agreement on production curbs in November 2014.

The U.S. Energy Information Administration, or EIA, forecasts that Brent crude oil prices will average $58 per Bbl in 2015 and $75 per Bbl in 2016. North Sea Brent crude oil spot prices averaged $62 per Bbl in December 2014, the lowest monthly average Brent price since May 2009, down $17 per Bbl from the November average. The combination of robust world crude oil supply growth and weak global demand has contributed to rising global inventories and falling crude oil prices. The EIA expects global oil inventories to continue to build in 2015, keeping downward pressure on oil prices. Like Brent crude oil prices, WTI prices have decreased considerably, with monthly average prices falling by more than 44% as of December 2014 after reaching their 2014 peak of $106 per Bbl in June. The EIA expects WTI crude oil prices to average $55 per Bbl in 2015 and $71 per Bbl in 2016.

The EIA expects the Henry Hub natural gas spot price to average $3.52 per MMBtu this winter compared with $4.51 per MMBtu last winter, reflecting both lower-than-expected space heating demand and higher natural gas production this winter. The EIA expects the Henry Hub natural gas spot price to average $3.44 per MMBtu in 2015 and $3.86 per MMBtu in 2016, compared with $4.39 per MMBtu in 2014. The EIA expects monthly average spot prices to remain less than $4 per MMBtu until the fourth quarter of 2016.

Commodity hedging remains an important part of our strategy to reduce cash flow volatility. Our hedging activities are intended to support oil and natural gas prices at targeted levels and to manage our exposure to oil and natural gas price fluctuations. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our 2014 Form 10-K for additional information.

We expect our 2015 development program and capital budget will be focused on the Terryville Complex, where we plan to allocate approximately 100% of our drilling and completion capital budget, primarily targeting our four primary zones within the Cotton Valley— the Upper Red, Lower Red, Lower Deep Pink and Upper Deep Pink.  We expect to fund our 2015 development primarily from cash flows from operations and borrowings under our revolving credit facility.  However, there can be no assurance that our operations or other capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures.

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Sources of Revenues

Both our and MEMP’s revenues are derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from natural gas during processing. Production revenues are derived entirely from the continental United States. Natural gas, NGL and oil prices are inherently volatile and are influenced by many factors outside our control. In order to reduce the impact of fluctuations in natural gas and oil prices on revenues, or to protect the economics of property acquisitions, both we and MEMP intend to periodically enter into derivative contracts with respect to a significant portion of estimated natural gas and oil production through various transactions that fix the future prices received. At the end of each period the fair value of these commodity derivative instruments are estimated and, because hedge accounting is not elected, the changes in the fair value of unsettled commodity derivative instruments are recognized in earnings at the end of each accounting period.

Principal Components of Cost Structure

● Lease operating expenses. These are the day to day costs incurred to maintain production of our natural gas, NGLs and oil. Such costs include utilities, direct labor, water injection and disposal, materials and supplies, compression, repairs and workover expenses. Cost levels for these expenses can vary based on supply and demand for oilfield services.

● Production and ad valorem taxes. These consist of severance and ad valorem taxes. Production taxes are paid on produced natural gas, NGLs and oil based on a percentage of market prices and at fixed per unit rates established by federal, state or local taxing authorities. Both we and MEMP take full advantage of all credits and exemptions in the various taxing jurisdictions where we operate. Ad valorem taxes are generally tied to the valuation of the oil and natural properties; however, these valuations are reasonably correlated to revenues, excluding the effects of any commodity derivative contracts.

● Exploration expense. These are geological and geophysical costs and include seismic costs, costs of unsuccessful exploratory dry holes and unsuccessful leasing efforts.

● Impairment of proved properties. Proved properties are impaired whenever the carrying value of the properties exceed their estimated undiscounted future cash flows.

● Depreciation, depletion and amortization. Depreciation, depletion and amortization, or DD&A, includes the systematic expensing of the capitalized costs incurred to acquire, exploit and develop natural gas and oil properties. As a “successful efforts” company, all costs associated with acquisition and development efforts and all successful exploration efforts are capitalized, and these costs are depleted using the units of production method.

● Incentive unit compensation expense. For more information regarding compensation expense recognized associated with incentive units, see Note 12 of the Notes to Consolidated and Combined Financial Statements under “Item 8. Financial Statements and Supplementary Data,” contained under Exhibit 99.2 of this Current Report.

● General and administrative expense. These costs include overhead, including payroll and benefits for employees, costs of maintaining headquarters, costs of managing production and development operations, compensation expense associated with certain long-term incentive-based plans, franchise taxes, audit and other professional fees, and legal compliance expenses.

● Interest expense. We and MEMP finance a portion of our working capital requirements and acquisitions with borrowings under revolving credit facilities and senior note issuances. As a result, we and MEMP incur substantial interest expense that is affected by both fluctuations in interest rates and financing decisions. We expect to continue to incur significant interest expense as we continue to grow.

● Income tax expense. 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 as the tax is assessed on 1% of taxable margin apportioned to operations in Texas.

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Results of Operations

MRD Segment

The MRD Segment’s consolidated and combined results of operations for the years ended December 31, 2014, 2013 and 2012 presented below have been derived from our predecessor’s and our consolidated and combined financial statements. The comparability of the results of operations among the periods presented is impacted by the following significant transactions:

● the sale of assets by BlueStone in East Texas in July 2013 for approximately $117.9 million;

● the acquisition by WildHorse Resources of assets in Louisiana in March 2013 for approximately $67.1 million; and

● the distribution by MRD LLC of the following to MRD Holdco: (i) BlueStone, which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owns certain immaterial leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owns an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline and (ii) 5,360,912 subordinated units of MEMP (which converted to common units on February 13, 2015).

Segment financial information has been retrospectively revised for material common control transactions between MEMP and MRD or its predecessor for comparability purposes, which includes the following transactions:

● acquisition by MEMP of certain oil and gas properties in East Texas and non-core Louisiana from MRD in exchange for MEMP’s North Louisiana oil and gas properties and approximately $78.0 million in cash in February 2015;

● acquisition by MEMP of all the outstanding membership interests in Tanos for a purchase price of approximately $77.4 million in October  2013;

● acquisition by MEMP of all the outstanding membership interests in Prospect Energy from Black Diamond for a purchase price of approximately $16.3 million in October 2013;

● acquisition by MEMP of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million in October 2013;

● acquisition by MEMP of all the outstanding membership interests in WHT for a purchase price of approximately $200.0 million in March 2013;

● acquisition by MEMP of certain assets from Classic in East Texas in May 2012 for a purchase price of approximately $27.0 million; and

● acquisition by MEMP of certain assets from Tanos in East Texas in April 2012 for a purchase price of approximately $18.5 million.

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	For the Year Ended December 31,
	2014			2013			2012
	(in thousands)
Oil & natural gas sales	$	363,114		$	201,886		$	103,728
Lease operating		17,570			17,315			16,582
Exploration		13,853			1,034			460
Production and ad valorem taxes		12,610			8,699			8,270
Depreciation, depletion, and amortization		128,238			70,903			37,048
Impairment of proved oil and natural gas properties		24,576			2,528			5,877
Incentive unit compensation expense		943,949			34,997			9,510
General and administrative		38,549			35,309			24,134
(Gain) loss on commodity derivative instruments		(257,734	)		(3,161	)		(10,500	)
(Gain) loss on sale of properties		3,057			(82,773	)		(2	)
Interest expense, net		(50,283	)		(24,948	)		(8,283	)
Loss on extinguishment of debt		(37,248	)		—			—
Income tax benefit (expense)		(102,392	)		(1,311	)		1
Net income (loss)		(764,333	)		91,390			8,810
Natural gas and oil revenue:
Oil sales	$	81,339		$	63,759		$	30,986
NGL sales		76,446			48,545			33,287
Natural gas sales		205,329			89,582			39,455
Total natural gas and oil revenue	$	363,114		$	201,886		$	103,728
Production Volumes:
Oil (MBbls)		908			631			323
NGLs (MBbls)		1,863			1,282			812
Natural gas (MMcf)		56,574			28,729			15,745
Total (MMcfe)		73,200			40,212			22,557
Average net production (MMcfe/d)		200.5			110.2			61.6
Average sales price:
Oil (per Bbl)	$	89.58		$	101.04		$	95.93
NGL (per Bbl)		41.03			37.85			40.99
Natural gas (per Mcf)		3.63			3.12			2.51
Total (Mcfe)	$	4.96		$	5.02		$	4.60
Average unit costs per Mcfe:
Lease operating expense	$	0.24		$	0.43		$	0.74
Production and ad valorem taxes	$	0.17		$	0.22		$	0.37
General and administrative expenses	$	0.53		$	0.88		$	1.07
Depletion, depreciation, and amortization	$	1.75		$	1.76		$	1.64

Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

The MRD Segment recorded a net loss of $764.3 million during 2014 compared to net income of $91.4 million during 2013. The net loss recorded during 2014 was primarily due to compensation expense associated with incentive units as discussed below.

● Oil and natural gas revenues for 2014 totaled $363.1 million, an increase of $161.2 million compared with 2013. Production increased 33.0 Bcfe (approximately 82%) primarily due to drilling activities in North Louisiana. The average realized sales price decreased $0.06 per Mcfe primarily due to lower oil prices. The favorable volume variance contributed to an approximate $165.6 million increase and was offset by $4.4 million due to the unfavorable pricing variances.

● Lease operating expenses were $17.6 million and $17.3 million for 2014 and 2013, respectively. On a per Mcfe basis, lease operating expenses decreased to $0.24 for 2014 from $0.43 for 2013. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges.

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● DD&A expense for 2014 was $128.2 million compared to $70.9 million for 2013, a $57.3 million increase primarily due to both an increase in the depletable cost base and increased production volumes related to drilling activities in North Louisiana. Increased production volumes caused DD&A expense to increase by an approximate $58.1 million and the change in the DD&A rate between periods caused DD&A expense to decrease by an approximate $0.8 million.

● Impairment expense for 2014 was $24.6 million compared to $2.5 million for 2013. The impairments primarily related to certain properties located in the Rockies and certain fields in North Louisiana. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily due to a decline in prices.

● Incentive unit compensation expense for 2014 was $943.9 million, of which $831.1 million related to WildHorse Resources incentive units, $111.8 million related to MRD Holdco incentive units, and $1.0 million related to BlueStone incentive units. We recognized $35.0 million of compensation expense associated with long-term incentive plans for 2013. Incentive unit compensation expense of approximately $20.7 million was recorded by BlueStone, $10.0 million related to WildHorse Resources and 4.3 million related to the Black Diamond management buyouts in 2013. Net proceeds generated from the sale of oil and gas properties were used to pay a distribution to BlueStone incentive unit holders.

● General and administrative expenses for 2014 were $38.5 million compared to $35.3million for 2013. General and administrative expenses for 2014 included $2.3 million of acquisition-related costs. General and administrative expenses for 2013 included $1.6 million of acquisition-related costs. Increased salaries and employee headcount also contributed to increased general and administrative expenses between periods.

● Net gains on commodity derivative instruments of $257.7 million were recognized during 2014, consisting of $9.2 million of cash settlement receipts in addition to a $248.5 million increase in the fair value of open hedge positions. Net gains on commodity derivative instruments of $3.2 million were recognized during 2013, consisting of $8.5 million of cash settlement receipts offset by a $5.3 million decrease in the fair value of open hedge positions.

● Net interest expense during 2014 was $50.3 million, including amortization of deferred financing fees of approximately $3.2 million. Net interest expense during 2013 was $24.9 million, including amortization of deferred financing fees of approximately $2.5 million. The increase in net interest expense is primarily the result of higher level of indebtedness during 2014 compared to 2013, including the MRD Senior Notes and the PIK notes.

Average outstanding borrowings under our revolving credit facility were $111.1 million during 2014. Average outstanding borrowings under the predecessor’s revolving credit facilities were $204.2 million during 2013. For the year ended December 31, 2014, we had an average of $634.5 million aggregate principal amount of the MRD Senior Notes, PIK notes and WildHorse Resources’ second lien term facility issued and outstanding. For the year ended December 31, 2013, we had an average of $13.4 million aggregate principal amount of the PIK notes issued and outstanding and an average of $179.9 million aggregate principal outstanding for the WildHorse Resources’ second lien term facility.

● During 2014, we sold certain producing and non-producing properties in the Mississippian oil play in Northern Oklahoma to a third party and recorded a loss of $3.2 million. During 2013, BlueStone entered into an agreement with a third party to sell its remaining interest in certain properties and recognized a gain of $89.5 million. This gain was offset by a loss of $6.8 million recorded by Black Diamond on the sale of certain oil and gas properties.

● An extinguishment loss of $23.6 million was recognized related to the redemption of the PIK notes. In connection with the closing of our initial public offering, 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.

● We are organized as a taxable C corporation and subject to federal and certain state income taxes. We recorded tax expense of $102.4 million in 2014 subsequent to our initial public offering. Taxes recognized in 2014 related primarily to deferred items such as hedging gains and oil and natural gas property temporary differences. Prior to our initial public offering we were a flow through entity.

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Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012

The MRD Segment recorded net income of $91.4 million in 2013 compared to a net loss of $8.8 million in 2012. The increase in net income was primarily due to gains on sales of properties and increased production.

● Oil and natural gas revenues were $201.9 million in 2013, an increase of $98.2 million from 2012. Production increased 17.7 Bcfe (approximately 78%) while the average realized sales price increased $0.42 per Mcfe. Production volume increases were primarily due to acquisitions and drilling activities in the Cotton Valley formation in North Louisiana. The favorable volume variance contributed to a $81.2 million increase in revenues, and the favorable pricing variance contributed to a $17.0 million increase in revenues.

● Lease operating expenses were $17.3 million in 2013, an increase in $0.7 million from 2012. This increase was primarily due to acquisitions and drilling activities in the Cotton Valley formation in North Louisiana. However, on a per Mcfe basis, lease operating expenses decreased by $0.31 per Mcfe as certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges.

● The $33.9 million increase in DD&A expense was primarily due to increased production volumes related to acquisitions and drilling activities in the Cotton Valley formation in North Louisiana. Increased production volumes increased DD&A expense by $29.0 million, while a 7% increase in the DD&A rate between periods increased DD&A expense by $4.9 million. On a per Mcfe basis, DD&A expense increased by $0.12 per Mcfe from 2012 to 2013.

● During 2013 and 2012, the MRD Segment recorded impairments of $2.5 million and $5.9 million, respectively, primarily related to certain fields in East Texas and North Louisiana. For these impairments, the estimated future cash flows expected from properties in these fields were compared to their carrying values and determined to be unrecoverable. Downward revisions due to performance and declines in natural gas prices triggered the 2013 and 2012 impairments, respectively.

● Incentive unit compensation expense for 2013 was $35.0 million as discussed above, which related to incentive unit payments to certain key management members of certain MRD LLC subsidiaries compared to approximately $9.5 million recorded in 2012.  

● General and administrative expenses were $35.3 million in 2013, an increase of $11.2 million from 2012. The increase in general and administrative expenses was primarily due to growth in employees as a result of acquisitions and development activities.

● Gains on commodity derivative instruments of $3.2 million were recognized during 2013, of which $8.5 million consisted of cash settlements received. Gains on commodity derivative instruments of $10.5 million were recognized during 2012, of which $20.7 million consisted of cash settlements received. The decrease in cash settlements received was primarily due to higher natural gas prices.

● During 2013, BlueStone entered into an agreement with a publicly traded third party to sell its remaining interest in certain properties in the Mossy Grove Prospect in Walker and Madison Counties located in East Texas and recognized a gain of $89.5 million. This gain was offset by a loss of $6.8 million recorded by Black Diamond on the sale of certain of its Wyoming oil and gas properties. During 2012, gains of less than $0.1 million were recognized by the MRD Segment.

● Net interest expense during 2013 was $24.9 million, including amortization of deferred financing fees of approximately $2.5 million and losses on interest rate swaps of $0.2 million. Net interest expense during 2012 was $8.3 million, including amortization of deferred financing fees of approximately $1.6 million and losses on interest rate swaps of $1.2 million. The increase in net interest expense is primarily the result of higher level of indebtedness during 2013 compared to 2012. Average debt outstanding was $397.5 million and $194.3 million for 2013 and 2012, respectively.

MEMP Segment

The MEMP Segment’s consolidated and combined results of operations for the years ended December 31, 2014, 2013 and 2012 presented below have been derived from our consolidated and combined financial statements included under “Item 8. Financial and Supplementary Data,” contained under Exhibit 99.2 of this Current Report.

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The comparability of the results of operations among the periods presented is impacted by the following significant transactions:

● two separate third party acquisitions by MEMP of assets in East Texas in May and September 2012, respectively, for a combined net purchase price of approximately $126.9 million;

● third party acquisition of working interests, royalty interests and net revenue interests located in the Permian Basin in July 2012 for a net purchase price of approximately $74.7 million;

● the 2012 divestiture of the offshore Louisiana properties by MEMP’s previous owners to a related party;

● multiple third party acquisitions of operated and non-operated interests in certain oil and natural gas properties primarily located in the Permian Basin for an aggregate net purchase price of $75.9 million during 2013;

● the Eagle Ford Acquisition in March 2014 for a net purchase price of $168.1 million; and

● the MEMP Wyoming Acquisition in July 2014 for a purchase price of approximately $906.1 million.

	For the Year Ended December 31,
	2014			2013			2012
	(in thousands)
Oil & natural gas sales	$	531,853		$	370,062		$	289,912
Lease operating		143,733			96,433			87,972
Exploration		2,750			1,322			9,340
Production and ad valorem taxes		33,141			18,447			15,354
Depreciation, depletion, and amortization		185,955			113,814			101,624
Impairment of proved oil and natural gas properties		407,540			4,072			22,994
General and administrative		49,124			46,665			35,112
(Gain) loss on commodity derivative instruments		(492,254	)		(26,133	)		(24,405	)
(Gain) loss on sale of properties		—			(2,848	)		(9,759	)
Interest expense, net		(83,550	)		(44,302	)		(24,955	)
Net income (loss)		115,614			61,005			23,067
Natural gas and oil revenue:
Oil sales	$	266,216		$	174,296		$	149,381
NGL sales		74,003			56,551			29,972
Natural gas sales		191,634			139,215			110,559
Total natural gas and oil revenue	$	531,853		$	370,062		$	289,912
Production Volumes:
Oil (MBbls)		3,135			1,797			1,565
NGLs (MBbls)		2,498			1,806			830
Natural gas (MMcf)		48,721			41,287			38,130
Total (MMcfe)		82,520			62,907			52,503
Average net production (MMcfe/d)		226.1			172.3			143.8
Average sales price:
Oil (per Bbl)	$	84.92		$	96.99		$	95.45
NGL(per Bbl)		29.62			31.31			36.11
Natural gas (per Mcf)		3.93			3.37			2.90
Total (Mcfe)	$	6.45		$	5.88		$	5.52
Average unit costs per Mcfe:
Lease operating expense	$	1.74		$	1.53		$	1.68
Production and ad valorem taxes	$	0.40		$	0.29		$	0.29
General and administrative expenses	$	0.60		$	0.74		$	0.67
Depletion, depreciation, and amortization	$	2.25		$	1.81		$	1.94

9

Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

Net income of $115.6 million was generated for the year ended December 31, 2014, primarily due to gains on commodity derivatives offset by impairment charges. Net income of $61.0 million was generated for the year ended December 31, 2013.

● Oil and natural gas sales for 2014 totaled $531.9 million, an increase of $161.8 million compared with 2013. Production increased 19.6 Bcfe (approximately 31%), primarily from volumes associated with third party acquisitions. The average realized sales price increased $0.57 per Mcfe primarily due to higher gas prices and an increase in oil volumes relative to other commodities due to MEMP’s acquisitions. The favorable volume and pricing variance contributed to an approximate $115.4 million and $46.4 million increase in revenues, respectively.

● Lease operating expenses were $143.7 million and $96.4 million for the year ended December 31, 2014 and 2013, respectively. In the MEMP Wyoming Acquisition, MEMP acquired oil properties, which are generally more expensive to operate compared to natural gas properties (on a per Mcfe basis). On a per Mcfe basis, lease operating expenses increased to $1.74 for 2014 from $1.53 for 2013.

● Production and ad valorem taxes for 2014 totaled $33.1 million, an increase of $14.7 million compared with 2013 primarily due to an increase in production volumes and ad valorem tax rates. On a per Mcfe basis, production and ad valorem taxes increased to $0.40 for 2014 from $0.29 for 2013 due to higher production tax rates on a per Mcfe basis for MEMP’s Wyoming Acquisition.

● DD&A expense for 2014 was $186.0 million compared to $113.8 million for 2013, a $72.1 million increase primarily due to both an increase in the depletable cost base and increased production volumes related to third party acquisitions and MEMP’s drilling program. Increased production volumes caused DD&A expense to increase by an approximate $35.5 million and the change in the DD&A rate between periods caused DD&A expense to increase by an approximate $36.6 million.

● MEMP recognized $407.5 million of impairments in 2014 related primarily to certain properties in the Permian Basin, East Texas, and South Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves as a result of declining commodity prices and updated well performance data. During 2013, MEMP recorded $4.1 million related to certain properties in South Texas. In South Texas, the estimated future cash flows expected these properties were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on pricing terms specific to these properties.

● General and administrative expenses for 2014 were $49.1 million and included $7.9 million of non-cash unit-based compensation expense and $4.4 million of acquisition-related costs and a $1.8 million allocated loss on a previous corporate office lease. General and administrative expenses for 2013 totaled $46.7 million and included $3.6 million of non-cash unit-based compensation expense and $6.7 million of acquisition-related costs. The $2.4 million increase in general administrative expenses consisted of increased salaries and employee count between periods.

● Net gains on commodity derivative instruments of $492.3 million were recognized during 2014, consisting of $13.6 million of cash settlement receipts in addition to a $478.7 million increase in the fair value of open hedge positions. Net gains on commodity derivative instruments of $26.1 million were recognized during 2013, consisting of $23.6 million of cash settlement receipts, in addition to a $2.5 million increase in the fair value of open hedge positions.

● Net interest expense is comprised of interest on credit facilities, interest on MEMP’s outstanding senior notes, amortization of debt issue costs, accretion of net discount associated with the senior notes and gains and losses on interest rate swaps. Net interest expense totaled $83.6 million during 2014, including amortization of deferred financing fees of approximately $4.2 million and accretion of net discount associated with the senior notes of $1.9 million. Net interest expense totaled $44.3 million during 2013, including gains on interest rate swaps of $1.5 million and amortization of deferred financing fees of approximately $6.0 million. The increase in net interest expense is primarily the result of higher level of indebtedness during 2014 compared to 2013, including MEMP’s 2022 Senior Notes.

10

Average outstanding borrowings under MEMP’s revolving credit facility were $413.6 million during 2014 compared to $184.7 million during 2013. Average outstanding borrowings under the previous owners’ revolving credit facilities were $101.3 million during 2013, which included $80.0 million of borrowings related to Classic. For the year ended December 31, 2014, MEMP had an average of $950.7 million aggregate principal amount of MEMP’s senior notes issued and outstanding. For the year ended December 31, 2013, MEMP had an average of $342.2 million aggregate principal amount of MEMP’s senior notes issued and outstanding.

Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012

MEMP recorded net income of $61.0 million in 2013 compared to income of $23.1 million in 2012.

● Oil and natural gas sales were $370.1 million in 2013, an increase of $80.2 million from 2012. Production increased 10.4 Bcfe (approximately 20%) while the average realized sales price increased $0.36 per Mcfe. The favorable volume variance contributed to a $57.5 million increase in revenues, whereas the favorable pricing variance contributed to a $22.7 million decrease in revenues.

● Lease operating expenses were $96.4 million in 2013, an increase of $8.5 million from 2012. Production and ad valorem taxes were $18.4 million in 2013, an increase of $3.1 million from 2012. Both lease operating expenses and production and ad valorem taxes increased primarily due to increased production volumes associated with properties acquired during both 2012 and 2013 and increased drilling activities.

● The increase in DD&A expense was primarily due to increased production volumes related to acquisitions in 2012 and 2013 and increased drilling activities. Increased production volumes caused DD&A expense to increase by $20.2 million, while a 7% change in the DD&A rate between periods caused DD&A expense to decrease by $8.0 million. An increase in proved reserve volumes more than offset the impact of increases to the depletable cost base.

● During 2013, MEMP recorded $4.1 million of impairments related to certain properties in South Texas. In South Texas, the estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on pricing terms specific to these properties. During 2012, MEMP recorded impairments of $23.0 million related to proved oil and natural gas properties which were a part of the Cinco Group of assets and certain oil and natural gas properties in East Texas. The $10.5 million of impairments related to the Cinco Group assets were a result of a downward revision of estimated proved reserves due to unfavorable drilling results in the area. The $12.5 million of impairments related to the East Texas properties were a result of a downward revision of estimated proved reserves based on pricing terms specific to these properties.

● General and administrative expenses were $46.7 million in 2013, an increase of $11.6 million. The increase in general and administrative expenses was primarily due to growth in employees as a result of acquisitions and drilling activities. General and administrative expenses for 2013 included $3.6 million of non-cash unit-based compensation expense and $6.7 million of acquisition-related costs. General and administrative expenses for 2012 were $35.1 million and included $1.4 million of non-cash unit-based compensation expense and $4.1 million of acquisition-related costs.

● Net gains on commodity derivative instruments of $26.1 million were recognized during 2013, of which $23.6 million consisted of cash settlements received. Net gains on commodity derivative instruments of $24.4 million were recognized during 2012, of which $53.6 million consisted of cash settlements received. The decrease in cash settlements was primarily due to higher natural gas prices.

● During 2013, a gain of approximately $2.8 million was recorded due to the sale of certain non-operated properties in East Texas. During 2012, a gain of approximately $9.8 million was recognized related to the sale of properties in Garza and Ector Counties in Texas.

● Net interest expense during 2013 was $44.3 million, including amortization of deferred financing fees of approximately $6.0 million and gains on interest rate swaps of $1.5 million. Net interest expense during 2012 was $25.0 million, of which $10.4 million was attributable to Partnership’s revolving credit facility, including amortization of deferred financing fees of approximately $0.6 million and losses on interest rate swaps of $4.0 million. The increase in net interest expense is primarily the result of higher level of indebtedness during 2013 compared to 2012.

11

Consolidated

For consolidated results of operations, see MRD Segment and MEMP Segment above.

Liquidity and Capital Resources

Although results are consolidated for financial reporting, the MRD and MEMP Segments operate with independent capital structures. The MEMP Segment’s debt is nonrecourse to the Company. With the exception of cash distributions paid to the MRD Segment by the MEMP Segment related to MEMP partnership interests held by the Company the cash needs of each segment have been met independently with a combination of operating cash flows, asset sales, credit facility borrowings and the issuance of debt and equity. We expect that the cash needs of each of the MRD Segment and the MEMP Segment will continue to be met independently of each other with a combination of these funding sources.

MRD Segment

Historically, the primary sources of liquidity have been through borrowings under credit facilities, capital contributions from NGP and certain members of management, borrowings under a second lien term loan facility, issuance of senior notes, asset sales, including dropdowns to MEMP, and net cash provided by operating activities. The primary use of cash has been for the exploration, development and acquisition of natural gas and oil properties. As we pursue reserve and production growth, we continually monitor what capital resources, including equity and debt financings, are available to meet future financial obligations, planned capital expenditure activities and liquidity requirements. Any future success in growing proved reserves and production will be highly dependent on the capital resources available.

Currently, the primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our revolving credit facility. We also have the ability to issue additional equity and debt as needed through both private and public offerings. We may from time to time refinance our existing indebtedness including by issuing longer-term fixed rate debt to refinance shorter-term floating rate debt.

Based on our current oil and natural gas price expectations, we believe our cash flows provided by operating activities and availability under our revolving credit facility will provide us with the financial flexibility and wherewithal to meet our cash requirements, including normal operating needs, and pursue our currently planned 2015 development drilling activities. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production, and significant additional capital expenditures will be required to more fully develop our properties and acquire additional properties. We cannot assure you that operations and other needed capital will be available on acceptable terms, or at all.

As of December 31, 2014, our liquidity of $548.0 million consisted of $6.0 million of cash and cash equivalents and $542.0 million of available borrowings under our revolving credit facility. As of December 31, 2014, we had a working capital balance of $60.0 million. As of December 31, 2014, the borrowing base under our revolving credit facility was $725.0 million and we had $183.0 million of outstanding borrowings. The borrowing base under our revolving credit facility is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil and natural gas reserves, which will take into account the prevailing oil 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. The next borrowing base redetermination is scheduled for April 2015. A continuing decline in oil and natural gas prices or a prolonged period of lower oil and natural gas prices could result in a reduction of our borrowing base under our revolving credit facility and could trigger mandatory principal repayments.  

Capital Budget

The amount and timing of our capital expenditures is largely discretionary and within our control, with the exception of certain projects managed by other operators. If oil and natural gas prices decline below levels we deem acceptable, we may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside of our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and labor crews.

12

Capital expenditures totaled $490.1 million for the year ended December 31, 2014 and included $97.8 million related to acquisitions. In 2014, MRD spent approximately 95% of its capital expenditures in the Terryville Complex and 5% in the Rockies. Our current estimated drilling and completion capital expenditure budget for 2015 is $475.0 million to $525.0 million, with substantially all capital expenditures dedicated to the Terryville Complex.

Cash Flows from Operating, Investing and Financing Activities

The following tables summarize segment cash flows from operating, investing and financing activities for the periods indicated. For information regarding the individual components of our cash flow amounts, see the Statements of Consolidated and Combined Cash Flows under “Item 8. Financial and Supplementary Data,” contained under Exhibit 99.2 of this Current Report.  

MRD Segment

	For Year Ended December 31,
	2014			2013			2012
Net cash provided by (used in) operating activities	$	226,906		$	75,905		$	57,033
Net cash provided by (used in) investing activities:
Acquisition of oil and natural gas properties	$	(93,909	)	$	(67,098	)	$	(83,055	)
Additions to oil and gas properties		(376,123	)		(185,194	)		(104,581	)
Additions to other property and equipment		(16,969	)		(2,432	)		(1,267	)
Equity investments in MEMP Segment		(570	)		(521	)		(206	)
Distributions received from MEMP Segment related to partnership interests		6,144			26,006			19,263
Decrease (increase) in restricted cash		49,946			(49,347	)		—
Proceeds from the sale of oil and gas properties to third parties		6,700			151,187			—
Proceeds from the sale of MEMP common units		—			135,012			—
Other		(516	)		—			(3	)
Net cash provided by (used in) investing activities	$	(425,297	)	$	7,613		$	(169,849	)
Net cash provided by (used in) financing activities
Advances on revolving credit facilities	$	1,300,800		$	174,400		$	122,950
Payments on revolving credit facilities		(1,320,900	)		(200,500	)		(24,750	)
Proceeds from issuance of senior notes		600,000			343,000			—
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		(18,840	)		(20,250	)		(1,109	)
Purchase of additional interests in consolidated subsidiaries		(3,292	)		(13,865	)		—
Net proceeds from initial public offering		380,127			—			—
Repurchased shares under repurchase program		(161	)		—			—
Contribution from NGP affiliates related to sale of properties		1,165			—			7,033
Contributions from MEMP Segment		58,766			180,260			1,813
Distributions to Funds		—			(732,362	)		—
Distributions to MRD Holdco		(59,803	)		—			—
Distributions to noncontrolling interest		(325	)		(7,446	)		—
Distributions to MEMP Segment		(5,990	)		(89,570	)		(1,900	)
Distribution to NGP affiliates related to purchase of assets		(66,693	)		—			—
Distribution to NGP affiliates related to sale of assets, net of cash received		(32,770	)		—			—
Distributions made by previous owners		—			(2,590	)		(2,317	)
Other cash transfers from MEMP Segment		—			—			3,751
Other		269			(4,593	)		—
Net cash provided by (used in) financing activities	$	152,263		$	(48,516	)	$	105,471

Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

Operating Activities. Net cash flows provided by operating activities were $226.9 million during 2014 compared to $75.9 million during 2013. Production increased 33.0 Bcfe (approximately 82%) and average realized sales price decreased $0.06 per Mcfe as previously discussed above under “Results of Operations—MRD Segment.” Cash paid for interest during 2014 was $67.0 million compared to $18.5 million during 2013. During 2014, compensation expense of approximately $26.7 million was paid in cash related to WildHorse Resources’ incentive units compared to $35.0 million in 2013 related to incentive units.

13

Investing Activities. Total cash used in investing activities was $425.3 million during 2014 compared to $7.6 million provided during 2013. Cash used for the acquisition of oil and gas properties was $93.9 million during 2014 compared to $67.1 million used in 2013.  The 2014 and 2013 acquisitions were for certain properties located in Louisiana. Cash used for additions to oil and gas properties was $376.1 million during 2014 compared to $185.2 million during 2013, which consisted primarily of drilling and completion activities in the Cotton Valley in North Louisiana area. Additions to other property and equipment were $17.0 million which consisted primarily of computer hardware, software, and other leased office space build out during 2014. Distributions of $6.1 million were received from MEMP primarily from the subordinated units owned by MRD LLC through June 18, 2014 compared to $26.0 million during 2013 received from MEMP primarily from the common and subordinated units then owned by MRD LLC. In May 2014, Black Diamond sold certain producing and non-producing properties in the Mississippian oil play of Northern Oklahoma to a third party for cash consideration of approximately $6.7 million. On July 31, 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. On June 4, 2013, Black Diamond sold certain of its Wyoming oil and gas properties to a third party for cash consideration of approximately $32.9 million. In 2014, there was a decrease in restricted cash of $49.9 million, which was primarily due to $50.0 million being released from the debt service reserve account associated with the PIK notes. In November 2013, MRD LLC sold 7,061,294 MEMP common units in a secondary public offering, which generated net proceeds of $135.0 million.

Financing Activities. On June 18, 2014, we completed our initial public offering pursuant to which we sold 21,500,000 shares of our common stock to the public at an offering price of $19.00 per share. Net proceeds from our initial public offering were $380.1 million. We used approximately $360.0 million of our initial public offering proceeds to redeem the PIK notes on June 27, 2014, of which $351.8 million was classified as a financing activity and the remaining $8.2 million was classified as an operating activity representing interest expense.

Net repayments under revolving credit facilities were $20.1 million during 2014 compared to net repayments of $26.1 million during 2013. Amounts borrowed under our revolving credit facility were primarily incurred to repay the amounts outstanding under WildHorse Resources’ credit facilities in connection with the closing of our initial public offering. WildHorse Resources primarily utilized its revolving credit facility during 2014 to repurchase net profits interests from an affiliate of NGP. 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 one-time special $225.0 million distribution to MRD LLC, which MRD LLC subsequently distributed to the Funds. In connection with the closing of our initial public offering, WildHorse Resources’ second lien term loan was repaid in full, including a premium of approximately $3.3 million.

Net proceeds of $586.8 million from the issuance of the MRD Senior Notes during the year ending December 31, 2014 were used to repay portions of our borrowings outstanding under our revolving credit facility.

Distributions to NGP affiliates related to the purchase of assets were primarily related to WildHorse Resources’ February 2014 acquisition of net profits interests in the Terryville Complex from an affiliate of NGP for $63.4 million. MRD Royalty also acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from an affiliate of NGP for $3.3 million in March 2014. Distributions to NGP affiliates related to the sale of assets were $32.8 million. WildHorse Resources sold its subsidiary, WHR Management Company, to an affiliate of the Funds for approximately $0.2 million and $33.0 million of cash was a component of the net book value transferred. For additional information regarding this transaction, see Note 13 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial and Supplementary Data,” contained under Exhibit 99.2 of this Current Report.

MEMP paid $33.9 million to WildHorse Resources in connection with MEMP’s April 2014 acquisition of certain oil and natural gas properties in East Texas. MEMP paid $15.0 million to MRD in connection with MEMP’s acquisition of certain oil and gas properties in the Rockies in October 2014.  MEMP paid $55.4 million to WildHorse Resources in connection with MEMP’s March 2013 acquisition of all the outstanding equity interests in WHT. MEMP paid $96.4 million to MRD LLC related to acquisitions of certain oil and natural gas properties in October 2013. Tanos also distributed approximately $28.6 million to MRD LLC during 2013.

14

In connection with our initial public offering, certain former management members of WildHorse Resources contributed their 0.1% membership interest and incentive units in WildHorse Resources 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 $3.3 million. In November 2013, MRD LLC purchased noncontrolling interests in Black Diamond, Classic GP and Classic for $13.9 million in cash.

Distributions to MRD Holdco during 2014 were $59.8 million. Approximately $6.7 million of cash received by MRD LLC in connection with the sale of assets in May 2014 was distributed to MRD Holdco in connection with our initial public offering. We also reimbursed MRD LLC for the approximately $17.2 million interest payment that it made on the PIK notes on June 15, 2014, which was distributed to MRD Holdco. Remaining cash of $32.8 million released from the debt service reserve account in connection with the redemption and discharge of the PIK notes was also distributed to MRD Holdco.

Distributions to the Funds during 2013 were $732.4 million. From time to time, MRD LLC made distributions of cash to the Funds. The timing and amount of these cash distributions was within the discretion of the board of managers of MRD LLC and was based, in part, upon available cash, the performance of its business, and other relevant factors. In 2013, substantially all of the cash distributed to the Funds was sourced from long term borrowings or sales of assets or equity in MEMP. The sources to fund these distributions primarily included $225.0 million from the WildHorse second lien term loan, $210.0 million from the December 2013 PIK notes, $63.8 million from the sale of properties to third parties, $125.0 million from the sale of properties to MEMP and $105.0 million from the sale of 7,061,294 MEMP common units that MRD LLC owned. Distributions to the MEMP Segment during 2013 of $89.6 million were primarily used to repay indebtedness and terminate the revolving credit facility attributable to Classic. Distributions to noncontrolling interests and previous owners totaled $10.0 million in 2013. Deferred financing costs of approximately $18.8 million were incurred during 2014 compared to approximately $20.3 million during 2013.

Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012

Operating Activities. Net cash flows provided by operating activities were $75.9 million in 2013 compared to $57.0 million in 2012. Although production volumes increased 17.7 Bcfe (approximately 78%), net cash flows from operating activities were impacted by $35.0 million of compensation expense recognized in 2013 related to incentive unit payments, which was an increase of $25.5 million from 2012.

Investing Activities. Cash provided by investing activities was $7.6 million during 2013 compared to $169.8 million used in 2012. Cash used for the acquisition of oil and gas properties was $67.1 million in 2013 compared to $83.1 million in 2012. The 2013 acquisition was for certain properties located in Louisiana that were purchased in March 2013. The 2012 acquisitions consisted primarily of properties located in East Texas and North Louisiana.

Cash used for additions to oil and gas properties was $185.2 million in 2013 compared to $104.6 million in 2012. The additions in both 2013 and 2012 consisted primarily of drilling and completion activities focused on the Cotton Valley formation in North Louisiana and East Texas.

Distributions of $26.0 million were received in 2013 from MEMP related to the common and subordinated units owned by MRD LLC as compared to $19.3 million received in 2012. In November 2013, MRD LLC sold 7,061,294 MEMP common units in a public offering, which generated net proceeds of $135.0 million.

Proceeds from the sale of oil and gas properties totaled $151.2 million in 2013. In May 2013, Black Diamond sold certain of its Wyoming properties for approximately $33.0 million. In July 2013, BlueStone sold its interest in certain properties located in Walker and Madison Counties in East Texas for approximately $117.9 million. There were no sales of oil and gas properties in 2012.

Additions to restricted cash totaled $49.3 million and were primarily related to the $50.0 million debt service reserve established in connection with the issuance of the PIK notes in December 2013.

Financing Activities. Cash used in financing activities was $48.5 million in 2013 compared to cash provided by financing activities of $105.5 million in 2012. Net payments under revolving credit facilities were $26.1 million in 2013 compared to net borrowings of $98.2 million in 2012. In June 2013, WildHorse Resources received gross proceeds of $325.0 million under its second lien term loan and in December 2013, MRD LLC received gross proceeds of $343.0 million related to the issuance of the PIK notes. Deferred financing costs were $20.3 million in 2013 compared to $1.1 million in 2012. The increase in deferred financing costs was primarily due to the WildHorse second lien term loan and the PIK notes.

15

In November 2013, MRD LLC purchased the noncontrolling interests in Black Diamond, Classic GP and Classic for $13.9 million of aggregate consideration.

Cash received from the MEMP Segment in 2013 related to the sale of assets from the MRD Segment to the MEMP Segment was $180.3 million compared to $1.8 million.

Distributions to the Funds during 2013 were $732.4 million as discussed above. Distributions to the MEMP Segment during 2013 of $89.6 million were primarily used to repay indebtedness and terminate the revolving credit facility attributable to Classic. Distributions to noncontrolling interests and previous owners totaled $10.0 million in 2013 compared to $2.3 million in 2012.

MEMP Segment

	For Year Ended December 31,
	2014			2013			2012
Net cash provided by operating activities	$	254,273		$	201,703		$	183,983
Net cash provided by (used in) investing activities:
Acquisition of oil and natural gas properties	$	(1,083,761	)	$	(38,664	)	$	(277,623	)
Additions to oil and gas properties		(298,274	)		(174,821	)		(168,411	)
Additions to other property and equipment		(98	)		(238	)		(1,748	)
Additions to restricted investments		(3,976	)		(5,361	)		(4,599	)
Proceeds from the sale of oil and gas properties to third parties		—			4,525			34,521
Other		—			—			29
Net cash provided by (used in) investing activities	$	(1,386,109	)	$	(214,559	)	$	(417,831	)
Net cash provided by (used in) financing activities
Advances on revolving credit facilities	$	1,446,000		$	958,355		$	496,500
Payments on revolving credit facilities		(1,137,000	)		(1,565,537	)		(226,819	)
Proceeds from the issuances of senior notes		492,425			688,563			—
Deferred financing costs		(11,494	)		(20,924	)		(2,392	)
Net proceeds from public equity offering		540,778			490,138			194,304
Repurchases under MEMP unit repurchase program		(11,531	)	—				—
Restricted units returned to plan		(1,012	)	—				—
Capital contributions from previous owners		—			7,233			44,072
Contribution from NGP affiliate		—			2,013			38,125
Contribution from general partner		570			521			206
Contribution from MRD Segment		5,990			89,570			1,900
Distributions to partners		(154,852	)		(96,643	)		(34,436	)
Distributions to MRD Segment		(58,766	)		(180,260	)		(1,813	)
Distributions to NGP affiliates		—			(355,495	)		(242,174	)
Distributions made by previous owners		—			(2,552	)		(26,455	)
Other cash transfers to MRD Segment		—		—				(3,751	)
Other		—			(9,013	)		(34	)
Net cash provided by (used in) financing activities	$	1,111,108		$	5,969		$	237,233

Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

Operating Activities. Net income increased by $54.6 million as further discussed above under “Results of Operations—MEMP Segment,” and net cash provided by operating activities increased by $52.6 million. Cash paid for interest during 2014 was $63.7 million compared to $42.6 million during 2013. Net cash provided by operating activities included $7.8 million period-to-period increase in cash flow attributable to the timing of cash receipts and disbursements related to operating activities during 2014 compared to 2013.

Investing Activities. Net cash used in investing activities during 2014 was $1.39 billion, of which $1.08 billion was used to acquire oil and natural gas properties from third parties and $298.3 million was used for additions to oil and gas properties. Cash used in investing activities during 2013 was $214.6 million, of which $38.7 million was used to acquire oil and natural gas properties from a third parties and $174.8 million was used for additions to oil and gas properties. During the year ended December 31, 2013, Tanos had sales proceeds of $4.5 million related to the sale of oil and natural gas properties. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. During 2014 and 2013, additions to restricted investments were $4.0 million and $5.4 million, respectively.

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Financing Activities. During 2014, MEMP issued a total of 24,840,000 common units generating gross proceeds of approximately $553.3 million offset by approximately $12.5 million of costs incurred in conjunction with the issuance of common units. The net proceeds from these issuances were primarily used to repay borrowings under MEMP’s revolving credit facility. In March 2013, MEMP issued 9,775,000 common units generating gross proceeds of approximately $179.4 million offset by approximately $7.6 million of costs incurred in conjunction with the issuance of common units. The net proceeds from this equity offering, including MEMP GP’s proportionate capital contribution, partially funded the acquisition of all of the outstanding equity interests in WHT. In October 2013, MEMP issued 16,675,000 common units generating gross proceeds of $331.8 million offset by approximately $13.5 million of costs incurred in conjunction with the issuance of common units. The net proceeds from this equity offering, including MEMP GP’s proportionate contribution, were used to repay a portion of outstanding borrowings under MEMP’s revolving credit facility.

Distributions to partners during 2014 were $154.9 million compared to $96.6 million during 2013, of which the MRD Segment received $6.1 million during 2014 compared to $26.0 million during 2013. The increase in total distributions is due to both an increase in MEMP’s outstanding units between periods and an increase in the declared cash distribution rate per unit. The decrease in distributions to the MRD Segment is due to MRD LLC selling 7,061,294 common units in November 2013 and the distribution of 5,360,912 subordinated units to MRD Holdco in June 2014 in connection with our initial public offering.

MEMP paid $33.9 million to WildHorse Resources in connection with MEMP’s April 2014 acquisition of certain oil and natural gas properties in East Texas. MEMP paid $15.0 million to MRD in connection with MEMP’s October 2014 acquisition of certain oil and gas properties in the Rockies.  MEMP paid $55.4 million to WildHorse Resources in connection with its March 2013 acquisition of all of the outstanding equity interests in WHT and repaid $89.3 million of indebtedness under WHT’s credit facility. MEMP paid MRD LLC $96.4 million related to the October 2013 acquisition of certain oil and natural gas properties. Distributions to NGP and affiliates were $355.5 million and Tanos distributed approximately $28.6 million to MRD LLC during 2013.

MEMP’s previous owners received contributions of $7.2 million during 2013, of which Tanos received $5.9 million from MRD LLC. Distributions made by MEMP’s previous owners totaled $2.6 million during 2013. Contributions from the MRD Segment of $89.6 million during 2013 were primarily used to repay indebtedness and terminate the revolving credit facility attributable to Classic. 

MEMP had net payments of $607.2 million under its revolving credit facilities during 2013. Borrowings under revolving credit facilities were used primarily to fund distributions associated with acquisitions of oil and gas properties from affiliates of NGP. MEMP had borrowings of $1.45 billion under its revolving credit facility during 2014 that were used primarily to fund its acquisitions and drilling program. Deferred financing costs of approximately $11.5 million were incurred during 2014 compared to approximately $20.9 million during 2013.

MEMP had unit repurchases of $11.5 million and $1.0 million in units returned to the MEMP GP Long-Term Incentive Plan during 2014.

Net proceeds of $484.0 million from the issuance of the senior notes during 2014 were used to repay borrowings outstanding under MEMP’s revolving credit facility. Proceeds of $688.6 million from the issuances of senior notes were generated during 2013 and used to repay borrowings outstanding under MEMP’s revolving credit facility.

Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012

Operating Activities. Net cash flows provided by operating activities increased during 2013 primarily due to an increase in production volumes as a result of acquisitions and increased drilling activities. Cash flows provided by operating activities at the MEMP Segment are used primarily to fund distributions to its partners and additions to oil and gas properties. The previous owners primarily used cash flows provided by operating activities to fund its exploration and development expenditures.

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Investing Activities. Cash used in investing activities during 2013 was $214.6 million, of which $38.7 million was used to acquire oil and gas properties located in Wyoming and East Texas and $174.8 million was used for additions to oil and gas properties. Cash used in investing activities during 2012 was $417.8 million, of which $277.6 million was used to acquire oil and gas properties and $168.4 million was used for additions to oil and gas properties. The 2012 acquisitions included $126.9 million of acquisitions in East Texas and $150.7 million of acquisitions in the Permian Basin.

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil properties. During 2013 and 2012, additions to restricted investments were $5.4 million and $4.6 million, respectively.

Proceeds from the sale of oil and gas properties were $4.5 million in 2013 compared to $34.5 million in 2012. The 2013 sales primarily consisted of certain non-operated properties in East Texas while the 2012 sales primarily consisted of certain properties in Garza and Ector counties located in West Texas.

Financing Activities. Cash provided by financing activities was $6.0 million in 2013 compared to $237.2 million in 2012.

MEMP generated total net proceeds of $490.1 million from two separate equity offerings in 2013 as discussed above compared to $194.3 million in December 2012. The net proceeds from the December 2012 offering were used to fund a portion of MEMP’s Beta acquisition and to repay indebtedness under MEMP’s revolving credit facility.

As discussed above, the net proceeds from the issuance of senior notes during 2013 were used to repay indebtedness under MEMP’s revolving credit facility. No senior notes were issued during 2012.

Distributions to partners were $96.6 million during 2013 compared to $34.4 million during 2012 due to increases in both declared distribution rates per unit and increases in the number of outstanding units. Distributions to the MRD Segment totaled $180.3 million in 2013 compared to $1.8 million in 2012. These distributions were primarily associated with the acquisition of assets by MEMP from the MRD Segment. Distributions to NGP affiliates were $355.5 million in 2013 compared to $242.2 million in 2012. The 2013 distribution was associated with the acquisition of assets by MEMP from certain affiliates of NGP in October 2013. The 2012 distribution was associated with the acquisition of assets located offshore Southern California from an affiliate of NGP.

MEMP’s previous owners received contributions of $7.2 million during 2013 compared to $44.1 million during 2012. Distributions made by MEMP’s previous owners totaled $2.6 million during 2013 compared to $26.5 million during 2012.  Contributions from the MRD Segment of $89.6 million during 2013 were primarily used to repay indebtedness and terminate the revolving credit facility attributable to Classic. 

MEMP had net payments of $607.2 million during 2013 related to revolving credit facilities. Borrowings under revolving credit facilities were used primarily to fund distributions associated with acquisitions of oil and gas properties from affiliates of NGP. Net proceeds from the issuance of the senior notes and common unit public equity offerings were used to repay borrowings under MEMP’s revolving credit facility. During 2012, MEMP had net borrowings of $269.2 million related to revolving credit facilities. These borrowings were primarily used to fund distributions associated with acquisitions of oil and gas properties from affiliates of NGP. Deferred financing costs of $20.9 million were incurred during 2013 associated with both the senior notes and MEMP’s revolving credit facility compared to $2.4 million incurred in 2012 related to revolving credit facilities.

Debt Agreements—MRD Segment

Revolving Credit Facility

In June 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 a borrowing base of $725 million as of December 31, 2014.  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. In the future, we may be unable to access sufficient capital under the revolving credit facility as a result of (i) a decrease in our borrowing base due to a subsequent borrowing base redetermination or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.

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A further decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we could be required to pledge other oil and natural gas properties as additional collateral. If a redetermination of our borrowing base results in our borrowing base being less than our aggregate elected commitments, our aggregate elected commitments will be automatically reduced to the amount of such reduced borrowing base. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility.

The revolving credit commitments could be terminated and any outstanding indebtedness together with accrued interest, fees and other obligations under the revolving credit facility, could be declared immediately due and payable if there is a default under our revolving credit facility.

We believe we were in compliance with all the financial (interest coverage ratio and current ratio) and other covenants associated with our revolving credit facility as of December 31, 2014.

See Note 8 under “Item 8. Financial Statements and Supplementary Data” contained under Exhibit 99.2 of this Current Report for additional information regarding our revolving credit facility.

MRD Senior Notes

In July 2014, MRD completed a private placement of $600.0 million aggregate principal amount of 5.875% senior unsecured notes due 2022 (the “MRD Senior Notes”). The MRD Senior Notes will mature on July 1, 2022 with interest accruing at a rate of 5.875% per annum and payable semi-annually in arrears on January 1 and July 1 of each year.  The MRD Senior Notes are governed by an indenture dated as of July 10, 2014. The MRD Senior Notes are fully and unconditionally guaranteed, subject to customary release provisions, on a senior unsecured basis by certain of our existing subsidiaries. See Note 8 under “Item 8. Financial Statements and Supplementary Data” contained under Exhibit 99.2 of this Current Report for additional information regarding the MRD Senior Notes.

Debt Agreements—MEMP Segment

MEMP Revolving Credit Facility

Memorial Production Operating LLC (“OLLC”), a wholly-owned subsidiary of MEMP, is party to a $2.0 billion revolving credit facility, with a current borrowing base of $1.44 billion that matures in March 2018 and is guaranteed by MEMP and all of its current and future subsidiaries (other than certain immaterial subsidiaries). See Note 8 under “Item 8. Financial Statements and Supplementary Data” contained under Exhibit 99.2 of this Current Report for additional information regarding MEMP’s revolving credit facility.

Senior Notes

In April 2013, May 2013 and October 2013, MEMP and Memorial Production Finance Corporation (“Finance Corp.”) (collectively, “the Issuers”) issued $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 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 were issued under and are governed by an indenture dated as of April 17, 2013.

In July 2014, the Issuers completed a private placement of $500.0 million aggregate principal amount of their 6.875% senior unsecured notes due 2022 (the “2022 Senior Notes”). The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by 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. The 2022 Senior Notes were issued under and are governed by an indenture dated as of July 17, 2014.

See Note 8 under “Item 8. Financial Statements and Supplementary Data” contained under Exhibit 99.2 of this Current Report for additional information regarding the 2021 Senior Notes and 2022 Senior Notes.

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Contractual Obligations

In the table below, we set forth our consolidated contractual obligations as of December 31, 2014 disaggregated by business segment. The contractual obligations that will actually be paid in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.

			Payment Due by Period (in thousands)
Purchase commitment	Total		2015		2016-2017		2018-2019		Thereafter
Revolving credit facility (1)
MRD Segment	$	183,000	$	—	$	—	$	183,000	$	—
MEMP Segment		412,000		—		—		412,000		—
Estimated interest payments (2)
MRD Segment		15,477		3,642		7,283		4,552		—
MEMP Segment		47,512		11,179		22,359		13,974		—
Senior Notes (3)
MRD Segment		881,217		37,404		70,500		70,500		702,813
MEMP Segment		1,823,657		89,469		175,500		175,500		1,383,188
Asset retirement obligation (4)
MRD Segment		9,829		—		1,607		2,127		6,095
MEMP Segment		112,702		—		5,266		3,765		103,671
Decommissioning trust agreement (5)
MEMP Segment		10,350		4,140		6,210		—		—
Operating leases (6)
MRD Segment		43,625		6,534		13,301		12,219		11,571
MEMP Segment		3,665		788		621		410		1,846
Compression services
MRD Segment		1,860		1,860		—		—		—
MEMP Segment		6,526		6,526		—		—		—
Drilling services
MRD Segment		48,543		48,543		—		—		—
Processing Plant Demand Fees (7)
MRD Segment		375,560		37,941		91,125		57,818		188,676
CO2 minimum purchase commitment (8)
MEMP Segment		50,495		9,608		20,330		14,055		6,502
MRD subtotal		1,559,111		135,924		183,816		330,216		909,155
MEMP subtotal		2,466,907		121,710		230,286		619,704		1,495,207
Total		4,026,018		257,634		414,102		949,920		2,404,362

(1) Represents the scheduled future maturities of principal amounts outstanding for the periods indicated. See the Notes to the Consolidated and Combined Financial Statements under “Item 8. Financial Statements and Supplementary Data,” contained under Exhibit 99.2 of this Current Reportfor information regarding our revolving credit facilities.

(2) Estimated interest payments are based on the principal amount outstanding under revolving credit facilities at December 31, 2014. In calculating these amounts, we applied the weighted-average interest rate during 2014 associated with such debt. See the Notes to the Consolidated and Combined Financial Statements under “Item 8. Financial Statements and Supplementary Data,” contained under Exhibit 99.2 of this Current Reportfor the weighted-average variable interest rate charged during 2014 under these credit facilities. In addition, the estimate of payments for interest gives effect to interest rate swap agreements that were in place at December 31, 2014.

(3) Represents the scheduled future interest payments and principal payments on the Senior Notes. See the Notes to the Consolidated and Combined Financial Statements under “Item 8. Financial Statements and Supplementary Data,” contained under Exhibit 99.2 of this Current Reportfor information regarding debt agreements.

(4) Asset retirement obligations represent estimated discounted costs for future dismantlement and abandonment costs. These obligations are recorded as liabilities on our December 31, 2014 balance sheet. See the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” contained under Exhibit 99.2 of this Current Reportfor additional information regarding our asset retirement obligations.

(5) Pursuant to a BOEM decommissioning trust agreement, MEMP is required to fund a trust account to comply with supplemental regulatory bonding requirements related to MEMP decommissioning obligations for its offshore Southern California production facilities. See the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” contained under Exhibit 99.2 of this Current Reportfor additional information.

(6) Primarily represents leases for office space and MEMP’s offshore Southern California right-of-way use.  See the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” contained under Exhibit 99.2 of this Current Reportfor additional information regarding operating leases.

(7) Represents minimum commitments to the gatherer.  See the Notes to the Consolidated and Combined Financial Statements under “Item 8. Financial Statements and Supplementary Data” contained under Exhibit 99.2 of this Current Reportfor information regarding processing plant demand fees.

(8) Represents a firm agreement, which MEMP assumed in the Wyoming Acquisition, to purchase CO₂ volumes.

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Critical Accounting Policies and Estimates

Natural Gas and Oil Properties

We use the successful efforts method of accounting to account for our natural gas and oil properties. 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 a 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 natural gas and oil reserves related to the associated field. Capitalized drilling and development costs of producing natural gas and oil 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 eliminated from the property accounts, and any gain or loss is recognized.

Proved Natural Gas and Oil Reserves

The estimates of proved natural gas and oil 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 FASB. These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements We intend to have our internally prepared reserve report as of December 31 of each year audited for a vast majority of our proved reserves and to prepare internal estimates of our proved reserves as of June 30 of each year.

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. Oil and gas properties are depleted by field using the units-of-production method. 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 natural gas and oil reserves, the remaining estimated lives of natural gas and oil properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

A decline in proved reserves may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of oil and gas producing properties for impairment.

Impairments

Proved natural gas and oil properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates, less than expected production, drilling results, 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.

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Incentive Units

Prior to our initial public offering, the governing documents of MRD LLC and certain of MRD LLC’s subsidiaries, including WildHorse Resources and BlueStone, provided for the issuance of incentive units. Those 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.

WildHorse Resources, BlueStone 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) have been achieved. Payouts would have been generally triggered after the recovery of specified members’ capital contributions plus a rate of return.

Vesting of incentive units is 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 are forfeited if an employee is no longer employed. All incentive units will be forfeited if a holder resigns whether the incentive units are vested or not. If the payouts have not yet occurred, then all incentive units, whether or not vested, will be forfeited automatically (unless extended).

In connection with the closing of our initial public offering, certain former management members of WildHorse Resources contributed to us their incentive units in WildHorse Resources, as well as the remaining 0.1% of the membership interests in WildHorse Resources in exchange for approximately 42.3 million shares of our common stock and cash consideration of $30.0 million. See Note 12 of the Notes to Consolidated and Combined Financial Statements under “Item 8. Financial and Supplementary Data,” contained under Exhibit 99.2 of this Current Report for additional information.

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 the period in which the performance conditions are probable of being satisfied. The compensation expense recognized by us related to the incentive units will be offset by a deemed capital contribution from MRD Holdco. See Note 12 of the Notes to Consolidated and Combined Financial Statements under “Item 8. Financial and Supplementary Data,” under Exhibit 99.2 of this Current Report for additional information.

Derivative Instruments

Commodity derivative financial instruments (e.g., swaps, floors, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under credit facilities. Every derivative instrument is recorded in the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized currently in earnings as we have not elected hedge accounting for any of our derivative positions.

Income Tax

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 as the tax is assessed on 1% of taxable margin apportioned to operations in Texas.

Deferred federal and state income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. If it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. In evaluating realizability of deferred tax assets, the Company refers to the reversal periods for available carryforward periods for net operating losses and credit carryforwards, temporary differences, the availability of tax planning strategies, the existence of appreciated assets and estimates of future taxable income and other factors. Estimates of future taxable income are based on assumptions of oil and gas reserves and selling prices that are consistent with the Company’s internal business forecasts.

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A tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority.

In June 2014, we recorded a deferred tax liability 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.

Off–Balance Sheet Arrangements

As of December 31, 2014, we had no off–balance sheet arrangements.

Recently Issued Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see the Notes to the Consolidated and Combined Financial Statements under “Item 8. Financial and Supplementary Data”contained under Exhibit 99.2 of this Current Report. As discussed under Note 2 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” contained under Exhibit 99.2 of this Current Report, the FASB issued an accounting standards update to improve consolidation guidance for certain types of legal entities in February 2015.  The guidance, among other things, modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities and eliminates the presumption that a general partner should consolidate a limited partnership. 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.

Section 107 of the Jumpstart Our Business Startups Act (“JOBS Act”) provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards, but we have irrevocably opted out of the extended transition period and, as a result, we will adopt new or revised accounting standards on the relevant dates in which adoption of such standards is required for other public companies.

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