mrd-ex991_899.htm

The following selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained herein and “Item 8. Financial Statements and Supplementary Data,” contained under Exhibit 99.2 of this report.

Basis of Presentation. The selected financial data as of, and for the years ended, December 31, 2015, 2014, 2013 and 2012 presented below have been derived from our consolidated financial statements and those of our predecessor and the previous owners on a combined basis for periods prior to our initial public offering. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. On June 1, 2016, we completed the sale of MEMP GP, the general partner of MEMP, Beta Operating Company, LLC and MEMP Services LLC (collectively, the “Disposition Entities”) to MEMP for total proceeds of $0.75 million. Because we controlled MEMP until the completion of the sale, we had historically consolidated the operations of MEMP and its subsidiaries in our financial statements. Prior to the sale our only economic interest was our ownership of MEMP GP, which at the time of the sale owned an approximate 0.1% general partner interest in MEMP and 50% of the incentive distribution rights in MEMP. Our selected financial data has been retrospectively revised to reflect the Disposition Entities and its subsidiaries as discontinued operations for all periods presented.

Comparability of the information reflected in selected financial data. The comparability of the results of operations from continuing operations among the periods presented is impacted by the following significant transactions:

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

As a result of the factors listed above, the consolidated and combined historical results of operations and period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results.

	For the Year Ended December 31,
	2015			2014			2013			2012
	(In thousands, except per share data)
Statement of Operations Data:										(Unaudited)
Revenues:
Oil & natural gas sales	$	374,042		$	409,070		$	219,552		$	110,590
Other revenues		—			12			—			—
Total revenues		374,042			409,082			219,552			110,590

Costs and expenses:
Lease operating		24,903			17,570			17,207			15,782
Gathering, processing, and transportation		72,554			45,956			17,666			6,887
Gathering, processing, and transportation - affiliate		25,403			—			—			—
Exploration		8,969			13,853			1,034			460
Taxes other than income		14,896			12,610			8,699			8,270
Depreciation, depletion, and amortization		188,742			128,238			70,903			37,048
Impairment of proved oil and natural gas properties		—			24,576			2,528			5,877
Incentive unit compensation expense		35,142			943,949			34,997			9,510
General and administrative		46,288			38,549			35,414			24,565
Accretion of asset retirement obligations		417			533			593			551
(Gain) loss on commodity derivative instruments		(281,249	)		(257,734	)		(3,161	)		(10,500	)
(Gain) loss on sale of properties		(47	)		3,057			(82,773	)		(2	)
Other, net		—			(1	)		2			464
Total costs and expenses		136,018			971,156			103,109			98,912
Operating income (loss)		238,024			(562,074	)		116,443			11,678
Other income (expense):
Interest expense, net		(39,396	)		(50,283	)		(24,948	)		(8,283	)
Loss on extinguishment of debt		—			(37,248	)		—			—
Other, net		(1,022	)		320			143			534
Total other income (expense)		(40,418	)		(87,211	)		(24,805	)		(7,749	)
Income (loss) from continuing operations before income taxes		197,606			(649,285	)		91,638			3,929
Income tax benefit (expense)		(100,005	)		(102,392	)		(1,311	)		1
Net income (loss) from continuing operations		97,601			(751,677	)		90,327			3,930
Net income (loss) from discontinued operations		(395,491	)		115,614			61,005			23,067
Net income (loss)		(297,890	)		(636,063	)		151,332			26,997
Net income (loss) attributable to noncontrolling interest		(393,538	)		126,788			49,830			(2,701	)
Net income (loss) attributable to Memorial Resource Development Corp.		95,648			(762,851	)		101,502			29,698
Net (income) loss allocated to members		—			(20,305	)		(90,712	)		7,620
Net (income) loss allocated to previous owners		—			(1,425	)		(10,790	)		(37,318	)
Net (income) allocated to participating restricted stockholders		(734	)		—			—			—
Net (income) loss from discontinued operations		327			(314	)		—			—
Net income (loss) from continuing operations available to common stockholders	$	95,241		$	(784,895	)	$	—		$	—

Earnings per common share from continuing operations:
Basic	$	0.49		$	(4.08	)	$	—		$	—
Diluted	$	0.49		$	(4.08	)	$	—		$	—

Cash Flow Data:										(Unaudited)
Net cash flow provided by operating activities – continuing operations	$	412,742		$	225,690		$	88,472		$	56,421
Net cash used in investing activities – continuing operations		(922,784	)		(430,732	)		(152,759	)		(188,907	)
Net cash provided by (used in) financing activities – continuing operations		425,412			99,487			(801	)		101,807

Balance Sheet Data:							(Unaudited)
Working capital	$	450,950		$	266,685		$	44,909		$	63,189
Total assets		5,082,849			4,559,826			2,796,817			2,459,304
Total debt		1,012,064			770,545			853,859			229,200
Total equity		1,467,921			1,702,964			858,132			1,276,709

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 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 Annual Report on Form 10-K for the year ended December 31, 2015 (“2015 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 the 2015 Form 10-K.

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 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, Jay Graham, our Chief Executive Officer, and certain other 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. We are currently majority-owned by the group consisting of MRD Holdco, Mr. Graham, our Chief Executive Officer, and certain other 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.

Prior to June 1, 2016, we controlled 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 were required to consolidate MEMP for accounting and financial reporting purposes. Although consolidated for accounting and financial reporting, we each had independent capital structures. Prior to June 1, 2016, we were entitled to 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.

On June 1, 2016, we completed the sale of MEMP GP, the general partner of MEMP, Beta Operating Company, LLC and MEMP Services LLC (collectively, the “Disposition Entities”) to MEMP for total proceeds of $0.75 million. Our results of operations has been retrospectively revised to reflect the Disposition Entities and its subsidiaries as discontinued operations for all periods presented. Prior to the sale of the Disposition Entities and its subsidiaries we had two reportable segments, one of which was MEMP and its subsidiaries. Effective June 1, 2016, we now have one reportable business segment, which is engaged in the acquisition, exploration, development and production of oil and natural gas properties. Accordingly, we have retrospectively revised our segment disclosures for all periods presented.

Our financial position and future prospects, including our revenues, operating results, profitability, liquidity, future growth and the value of our assets, depend primarily on prevailing commodity prices. Starting in 2014, throughout 2015 and continuing into 2016, commodity prices dropped significantly, with the West Texas Intermediate posted price declining from $107 per Bbl in June 2014 to less than $30 per Bbl in January 2016 and the Henry Hub spot market price declining from $6 per MMBtu in February 2014 to less than $3 per MMBtu in January 2016. NGL prices have also suffered significant declines. A combination of oversupply from production growth and weaker demand due to weak economic activity and increased efficiency has contributed to the falling prices.

As a result of the significant decline in commodity prices and general uncertainty regarding the timing and nature of the recovery of prices in the future, we expect 2016 to be challenging and our strategic focus will be on reducing our operating costs and seeking to preserve as much of our liquidity and financial flexibility as possible in this lower commodity price environment.

The U.S. Energy Information Administration, or EIA, forecasts that Brent crude oil prices will average $38 per Bbl in 2016 and $50 per Bbl in 2017. North Sea Brent crude oil spot prices averaged $31 per Bbl in January 2016, the lowest monthly average Brent price since December 2003, down $7 per Bbl from the December 2015 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 2016, keeping downward pressure on oil prices. Like Brent crude oil prices, WTI prices have decreased considerably, with monthly average prices falling by more than 37% as of December 2015 after reaching their 2015 peak of $59.83 per Bbl in June. The EIA expects WTI crude oil prices to average $2 per Bbl lower than Brent in 2016 and $3 per Bbl lower in 2017.

The EIA expects that natural gas inventories will end the winter heating season in 2016 at 20% above the level at the same time last year. The EIA expects the Henry Hub natural gas spot price to average $2.64 per MMBtu in 2016 and $3.22 per MMBtu in 2017, compared with $2.63 per MMBtu in 2015. The EIA expects monthly average spot prices to remain less than $3 per MMBtu until 2017.

In January 2016, we established a full year 2016 capital expenditure budget that was approximately 30% lower than our 2015 capital expenditure budget. We expect our 2016 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 2016 development 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. We believe we have built significant flexibility into our 2016 capital budget, not only in the timing of completions, but also in our operated rig count. We will have the option to increase or decrease our capital activity as commodity prices dictate, which will allow us to preserve liquidity while maintaining flexibility in our completions schedule.

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” for additional information contained herein.

For a discussion of the potential impact of commodity price changes on our estimated proved reserves, including quantification of such potential impact, please read “Item 1. Business – Our Oil and Natural Gas Data – Reserves Sensitivity” included in our 2015 Form 10-K.

Commodity prices have historically been volatile, and we expect this volatility to continue for the foreseeable future. We will continue to monitor our liquidity, including opportunities for liquidity enhancement through possible joint-venture arrangements, coordinate our capital expenditure program with our expected cash flows and projected debt-repayment schedule, and evaluate available funding and other strategic alternatives in light of the current and expected commodity price environment and market conditions.

Our 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, we 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.

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.

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.

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.

Unproved oil and natural gas properties are reviewed for impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, the expense is reported in exploration expenses.

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

In connection with the closing of our initial public offering, Mr. Graham, our Chief Executive Officer, and certain other 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 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,” contained under Exhibit 99.2 of this report for additional information.

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 our credit facility. 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.

Embedded derivatives that are required to be bifurcated and accounted for separately are treated in the same manner as freestanding derivatives. Embedded derivatives are recorded at fair value, with the difference between the basis of the hybrid financial instrument and the fair value of the embedded derivative recorded as the carrying value of the host contract. See Note 6 of the Notes to Consolidated and Combined Financial Statements under “Item 8. Financial and Supplementary Data,” contained under Exhibit 99.2 of this report for further information on certain commodity contracts that required bifurcation.

We are a corporation subject to federal and certain state income taxes. 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 use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis in assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. We recognize interest and penalties accrued to unrecognized tax benefits in other income (expense) in our consolidated statement of operations.

We recognize a tax benefit from an uncertain tax position 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 effective settlement with a taxing authority.

Our results of operations for the years ended December 31, 2015, 2014, and 2013 presented below have been derived from our predecessor’s and our consolidated and combined financial statements. The comparability of the results of operations from continuing operations among the periods presented is impacted by the following significant transactions:

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

	For the Year Ended December 31,
	2015			2014			2013
	(in thousands)
Oil & natural gas sales	$	374,042		$	409,070		$	219,552
Lease operating		24,903			17,570			17,207
Gathering, processing, and transportation (including affiliate)		97,957			45,956			17,666
Exploration		8,969			13,853			1,034
Taxes other than income		14,896			12,610			8,699
Depreciation, depletion, and amortization		188,742			128,238			70,903
Impairment expense		—			24,576			2,528
Incentive unit compensation expense		35,142			943,949			34,997
General and administrative		46,288			38,549			35,414
(Gain) loss on commodity derivative instruments		(281,249	)		(257,734	)		(3,161	)
(Gain) loss on sale of properties		(47	)		3,057			(82,773	)
Interest expense, net		(39,396	)		(50,283	)		(24,948	)
Loss on extinguishment of debt		—			(37,248	)		—
Income tax benefit (expense)		(100,005	)		(102,392	)		(1,311	)
Net income (loss) from continuing operations		97,601			(751,677	)		90,327
Net income (loss) from discontinued operations		(395,491	)		115,614			61,005
Net income (loss)		(297,890	)		(636,063	)		151,332

Natural gas and oil revenue:
Oil sales	$	60,931		$	81,871		$	63,761
NGL sales		60,718			78,470			49,641
Natural gas sales		252,393			248,729			106,150
Total natural gas and oil revenue	$	374,042		$	409,070		$	219,552

Production Volumes:
Oil (MBbls)		1,331			908			631
NGLs (MBbls)		3,249			1,863			1,282
Natural gas (MMcf)		98,269			56,574			28,729
Total (MMcfe)		125,749			73,200			40,212
Average net production (MMcfe/d)		344.5			200.5			110.2

Average sales price:
Oil (per Bbl)	$	45.78		$	90.17		$	101.05
NGL (per Bbl)		18.69			42.12			38.72
Natural gas (per Mcf)		2.57			4.40			3.69
Total (Mcfe)	$	2.97		$	5.59		$	5.46

Average unit costs per Mcfe:
Lease operating expense	$	0.20		$	0.24		$	0.43
Gathering, processing, and transportation (including affiliate)		0.78			0.63			0.44
Taxes other than income		0.12			0.17			0.22
General and administrative expenses		0.37			0.53			0.88
Depletion, depreciation, and amortization		1.50			1.75			1.76

We recorded a net loss of $297.9 million during 2015 compared to a net loss of $636.1 million during 2014.

Given the volatility of commodity prices, it is not possible to predict future reported unrealized mark-to-market net gains or losses and the actual net gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If commodity prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower oil, natural gas and NGL prices. However, if commodity prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher oil, natural gas and NGL prices and will, in this context, be viewed as having resulted in an opportunity cost.

Average outstanding borrowings under our revolving credit facility were $230.5 million during 2015 and $60.0 million during 2014. Average outstanding borrowings under the predecessor’s revolving credit facilities were $116.7 million during 2014. During 2015, we had an average of $600.0 million aggregate principal amount of the MRD Senior Notes issued and outstanding. During 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.

We recorded a net loss of $636.1 million during 2014 compared to net income of $151.3 million during 2013. The net loss recorded during 2014 was primarily due to compensation expense associated with incentive units as discussed below.

Average outstanding borrowings under our revolving credit facility were $60.0 million during 2014. Average outstanding borrowings under the predecessor’s revolving credit facilities were $116.7 million during 2014 and $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.

Adjusted EBITDA 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 performance. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating results. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) from continuing operations, our most directly comparable financial measure calculated and presented in accordance with GAAP. 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.

Adjusted EBITDA is defined as net income (loss) from continuing operations, plus interest expense; loss on extinguishment of debt; income tax expense; depreciation, depletion and amortization (“DD&A”); impairment of long-lived properties; accretion of asset retirement obligations (“AROs”); losses on commodity derivative contracts and cash settlements received; losses on sale of properties; incentive-based compensation expenses; exploration costs; equity loss; cash distributions from MEMP; transaction related costs; and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and cash settlements paid; equity income; gains on sale of assets and other non-routine items.

The following table presents our calculation of Adjusted EBITDA for each of the periods presented:

	For the Year Ended December 31,
	2015			2014			2013
	(In thousands)
Net income (loss) from continuing operations	$	97,601		$	(751,677	)	$	90,327
Interest expense, net		39,396			50,283			24,948
Income tax expense (benefit)		100,005			102,392			1,311
Loss on extinguishment of debt		—			37,248			—
DD&A		188,742			128,238			70,903
Impairment of proved oil and natural gas properties		—			24,576			2,528
Accretion of AROs		417			533			593
(Gain) loss on commodity derivative instruments		(281,249	)		(257,734	)		(3,161	)
Cash settlements received (paid) on expired commodity derivative instruments		170,899			9,166			8,481
(Gain) loss on sale of properties		(47	)		3,057			(82,773	)
Transaction related costs		1,974			2,305			1,584
Incentive-based compensation expense		43,930			946,753			34,997
Exploration costs		8,969			13,853			1,034
Loss on office lease		—			1,180			—
Non-cash equity (income) loss		—			—			(784	)
Cash distributions from MEMP		252			6,144			26,006
Adjusted EBITDA	$	370,889		$	316,317		$	175,994

Historically, the primary sources of liquidity have been 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 2016 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, 2015, we had $577.0 million of available borrowings under our revolving credit facility. As of December 31, 2015, we had a working capital balance of $197.2 million (excluding discontinued operations), which includes a net asset balance of $274.1 million associated with our derivatives and other financial instruments. As of December 31, 2015, the borrowing base under our revolving credit facility was $1.0 billion and we had $423.0 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. 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.

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 all or 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.

Total capital expenditures were $880.0 million for the year ended December 31, 2015 and included $368.7 million associated with acquisitions and unproved leasehold additions. In 2015, we spent approximately 100% of our capital expenditures in the Terryville Complex. We expect that substantially all of our capital expenditures in 2016 will be dedicated to the Terryville Complex.

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 $1.0 billion as of December 31, 2015. 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.

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, 2015.

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

In July 2014, we 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 report for additional information regarding the MRD Senior Notes.

Cash Flows from Operating, Investing and Financing Activities—Continuing Operations

The following tables summarize cash flows from operating, investing and financing activities from continuing operations 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 report.

Operating Activities. Net cash flows provided by operating activities from continuing operations were $412.7 million during 2015 compared to $225.7 million during 2014. Production increased 52.5 Bcfe (approximately 72%) and average realized sales price decreased $2.62 per Mcfe as previously discussed above under “Results of Operations.” Net cash provided by operating activities included $92.3 million of cash receipts on terminated derivative instruments and $46.2 million of premiums paid for derivatives. Cash paid for interest during 2015 was $18.8 million compared to $67.0 million during 2014 due to timing of interest payments and lower interest rates. During 2014, compensation expense of approximately $26.7 million was paid in cash related to WildHorse Resources’ incentive units.

Investing Activities. Total cash used in investing activities from continuing operations was $922.8 million during 2015 compared to $430.7 million during 2014. Cash used for the acquisition of oil and gas properties was $291.5 million during 2015 compared to $93.9 million used in 2014. The 2015 and 2014 acquisitions were for certain properties located in Louisiana. Cash used for additions to oil and gas properties was $594.9 million during 2015 compared to $376.1 million during 2014, which consisted primarily of drilling and completion activities in North Louisiana. Additions to other property and equipment were $3.9 million during 2015 compared to $16.8 million during 2014. Additions to other financial instruments was $46.1 million in 2015. In April 2015, we sold certain oil and natural gas properties to a third party in Colorado and Wyoming for approximately $13.6 million. 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. 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.

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 borrowings under our revolving credit facility were $240.0 million during 2015. Amounts borrowed under our revolving credit facility were primarily used for additions to oil and natural gas properties and general corporate purposes. Net repayments under the revolving credit facility were $20.1 million during 2014. 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. In connection with the closing of our initial public offering, WildHorse Resources’ $325.0 million second lien term loan was repaid in full, including a premium of approximately $3.3 million.

On September 25, 2015, we issued 13,800,000 shares of common stock (including 1,800,000 shares of common stock sold pursuant to the full exercise of the underwriters’ option to purchase additional shares of common stock) to the public generating total net proceeds of approximately $238.1 million after deducting underwriting discounts and offering expenses. The net proceeds temporarily reduced borrowings outstanding under our revolving credit facility.

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 report.

In connection with our initial public offering, certain former management members of WildHorse Resources, including Mr. Graham, 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.

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.

Total payments remitted for employees’ tax obligations to the appropriate taxing authorities were approximately $1.2 million during 2015 upon vesting of the restricted common stock. The Company repurchased 2,888,684 shares of its common stock under its December 2014 repurchase program for an aggregate price of $50.0 million during 2015, which exhausted the December 2014 repurchase program. The Company has retired all of the shares of common stock repurchased and those shares of common stock are no longer issued or outstanding.

Deferred financing costs of approximately $1.5 million and $18.8 million were incurred during 2015 and 2014, respectively.

Operating Activities. Net cash flows provided by operating activities from continuing operations were $225.7 million during 2014 compared to $88.5 million during 2013. Production increased 33.0 Bcfe (approximately 82%) and average realized sales price increased $0.13 per Mcfe as previously discussed above under “Results of Operations.” 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.

Investing Activities. Total cash used in investing activities from continuing operations was $430.7 million during 2014 compared to $152.8 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 North Louisiana. Additions to other property and equipment were $16.8 million which consisted primarily of computer hardware, software, and other leased office space build out during 2014. 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.

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.

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.

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 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.

In the table below, we set forth our contractual obligations (excluding those attributable to discontinued operations) as of December 31, 2015. 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		2016		2017-2018		2019-2020		Thereafter

Revolving credit facility (1)	$	423,000	$	—	$	—	$	423,000	$	—
Estimated interest payments (2)		28,426		8,122		16,243		4,061		—
Senior Notes (3)		846,750		35,250		70,500		70,500		670,500
Asset retirement obligation (4)		9,249		354		2,550		1,090		5,255
Operating leases (5)		45,322		10,509		16,711		12,979		5,123
Drilling services		34,740		34,229		511		—		—
Midstream service fees (6)		1,306,187		142,461		231,990		236,280		695,456

Total		2,693,674		230,925		338,505		747,910		1,376,334

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 report.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than for speculative trading.

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of natural gas, NGL and oil prices. Natural gas, NGL and oil prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future cash flow from operations will depend on the prices of natural gas, NGL and oil and our ability to maintain and increase production through acquisitions and exploitation and development projects.

To reduce the impact of fluctuations in natural gas and oil prices on our revenues, or to protect the economics of property acquisitions, we periodically enter into derivative contracts with respect to a portion of our projected natural gas, NGL and oil production through various transactions to provide an economic hedge of the risk related to the future commodity prices received. These transactions may include price swaps, whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty, or basis swaps, whereby we will receive a fixed price differential and pay a variable price differential to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pays the excess, if any, of the floating rate over the fixed ceiling price. We also may enter into put options that are designed to provide a fixed price floor with the opportunity for upside. These economic hedging activities are intended to support natural gas and oil prices at targeted levels and to manage our exposure to natural gas, NGL and oil price fluctuations. We do not enter into derivative contracts for speculative trading purposes. Our revolving credit facility contains various covenants and restrictive provisions which, among other things, limit our ability to enter into commodity price hedges exceeding a certain percentage of production.

At December 31, 2015, we had the following open commodity positions (excluding embedded derivatives):

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

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

Purchased put option contracts:
Average Monthly Volume (MMBtu)		6,000,000			5,350,000
Weighted-average strike price	$	3.51		$	3.48
Weighted-average deferred premium paid	$	(0.34	)	$	(0.32	)

TGT Z1 basis swaps:
Average Monthly Volume (MMBtu)		1,120,000			200,000
Spread - Henry Hub	$	(0.10	)	$	(0.08	)

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		35,583			28,000
Weighted-average fixed price	$	83.58		$	84.70

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

NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		353,399			—
Weighted-average fixed price	$	39.68		$	—

During the year ended December 31, 2015, we restructured our existing 2018 crude oil and natural gas hedges for crude oil and NGL swaps that will settle in 2016. Cash settlements of approximately $92.3 million from the terminated 2018 positions were received and applied as premiums for the new crude oil and NGL swaps. Certain contracts are classified as hybrid financial instruments, which require bifurcation, based on the relationship between the fixed swap price and the market price at the restructure dates.

At December 31, 2015, the we had the following open embedded derivative positions:

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

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

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

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

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

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

Put option contracts:
Average Monthly Volume (Bbls)	$	26,000.00			—			—			—
Weighted-average strike price	$	85.00		$	—		$	—		$	—
Weighted-average deferred premium paid	$	(3.80	)	$	—		$	—		$	—

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

Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. As of December 31, 2015, we did not have open interest rate swap positions.

The fair value of the MRD Senior Notes is sensitive to changes in interest rates. We estimate the fair value of the MRD Senior Notes using quoted market prices. The carrying value (net of any discount or premium and debt issuance cost) is compared to the estimated fair value in the table below (in thousands):

Our principal exposures to credit risk are through receivables resulting from commodity derivatives and the sale of our oil and gas production, which we market to energy companies.

By using derivative and other financial instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the contract. When the fair value of a contract is positive, the counterparty is expected to owe us, which creates the credit risk. To minimize the credit risk in derivative and other financial instruments, it is our policy to enter into contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. The creditworthiness of our counterparties is subject to periodic review. As of December 31, 2015, our derivative and other financial contracts are with major financial institutions, certain of which are also lenders under our revolving credit facilities. While collateral is generally not required to be posted by counterparties, credit risk associated with these instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. At December 31, 2015, we had derivative and other financial assets of $365.4 million. After taking into effect netting arrangements, we had counterparty exposure of $169.1 million related to our derivative and other financial instruments. Had certain counterparties failed completely to perform according to the terms of their existing contracts, we would have the right to offset $196.3 million against amounts outstanding under our revolving credit facility at December 31, 2015. See Note 8 under “Item 8. Financial Statements and Supplementary Data” contained under Exhibit 99.2 of this report for additional information regarding our revolving credit facility.

We are also subject to credit risk due to the concentration of our natural gas and oil receivables with several significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

We have audited the accompanying consolidated balance sheets of Memorial Resource Development Corp. and subsidiaries (the Company) as of December 31, 2015 and 2014, the related consolidated statements of operations, equity, and cash flows for the year ended December 31, 2015, and the related consolidated and combined statements of operations, equity, and cash flows for each of the years in the two-year period ended December 31, 2014. These consolidated and combined financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated and combined financial statements based on our audits.

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

In our opinion, the consolidated and combined financial statements referred to above present fairly, in all material respects, the financial position of Memorial Resource Development Corp. and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated and combined financial statements, the statements of operations, equity, and cash flows for each of the years in the two-year period ended December 31, 2014 have been prepared on a combined basis of accounting.

As discussed in Note 1 and Note 2 to the consolidated and combined financial statements, Memorial Resource Development Corp. changed its method of accounting for debt issuance costs effective January 1, 2014 due to the adoption of FASB ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. Additionally, as discussed in Note 1 and Note 2 to the consolidated and combined financial statements, Memorial Resource Development Corp. changed its method of accounting for deferred income taxes effective January 1, 2014 due to the adoption of FASB ASU 2015-17, Balance Sheet Classification of Deferred Taxes.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Memorial Resource Development Corp. and subsidiaries’ internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 24, 2016 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

	December 31,			December 31,
	2015			2014
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	3,364
Accounts receivable:
Oil and natural gas sales		22,719			27,476
Joint interest owners and other		29,973			5,602
Short-term derivative instruments		227,991			131,471
Other financial instruments (Note 6)		46,106			—
Prepaid expenses and other current assets		3,374			11,344
Assets of discontinued operation (Note 3)		345,541			321,536
Total current assets		675,704			500,793
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method (Note 2)		2,160,008			1,317,102
Other		22,822			29,658
Accumulated depreciation, depletion and impairment		(438,383	)		(280,116	)
Property and equipment, net		1,744,447			1,066,644
Long-term derivative instruments		91,292			123,567
Other long-term assets		4,976			3,586
Assets of discontinued operation (Note 3)		2,566,430			2,865,236
Total assets	$	5,082,849		$	4,559,826

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	25,057		$	959
Accounts payable - affiliates		5,016			160
Revenues payable		34,026			21,807
Accrued liabilities (Note 2)		68,876			51,236
Liabilties of discontinued operation (Note 3)		91,779			159,946
Total current liabilities		224,754			234,108
Long-term debt		1,012,064			770,545
Asset retirement obligations		10,079			9,829
Deferred tax liabilities		193,733			114,599
Other long-term liabilities		7,195			8,585
Liabilities of discontinued operation (Note 3)		2,167,103			1,719,196
Total liabilities		3,614,928			2,856,862
Commitments and contingencies (Note 15)
Equity:
Stockholders' equity (deficit):
Preferred stock, $.01 par value: 50,000,000 shares authorized; no shares issued and outstanding		—			—
Common stock, $.01 par value: 600,000,000 shares authorized; 205,293,743 shares issued and outstanding at December 31, 2015; 193,435,414 shares issued and outstanding at December 31, 2014		2,053			1,935
Additional paid-in capital		1,560,949			1,367,346
Accumulated earnings (deficit)		(740,175	)		(786,871	)
Total stockholders' equity		822,827			582,410
Noncontrolling interests		645,094			1,120,554
Total equity		1,467,921			1,702,964
Total liabilities and equity	$	5,082,849		$	4,559,826

	For Year Ended December 31,
	2015			2014			2013
Revenues:
Oil & natural gas sales	$	374,042		$	409,070		$	219,552
Other revenues		—			12			—
Total revenues		374,042			409,082			219,552

Costs and expenses:
Lease operating		24,903			17,570			17,207
Gathering, processing, and transportation		72,554			45,956			17,666
Gathering, processing, and transportation – affiliate		25,403			—			—
Exploration		8,969			13,853			1,034
Taxes other than income		14,896			12,610			8,699
Depreciation, depletion, and amortization		188,742			128,238			70,903
Impairment of proved oil and natural gas properties		—			24,576			2,528
Incentive unit compensation expense		35,142			943,949			34,997
General and administrative		46,288			38,549			35,414
Accretion of asset retirement obligations		417			533			593
(Gain) loss on commodity derivative instruments		(281,249	)		(257,734	)		(3,161	)
(Gain) loss on sale of properties		(47	)		3,057			(82,773	)
Other, net		—			(1	)		2
Total costs and expenses		136,018			971,156			103,109
Operating income (loss)		238,024			(562,074	)		116,443
Other income (expense):
Interest expense, net		(39,396	)		(50,283	)		(24,948	)
Loss on extinguishment of debt		—			(37,248	)		—
Other, net		(1,022	)		320			143
Total other income (expense)		(40,418	)		(87,211	)		(24,805	)
Income (loss) from continuing operations before income taxes		197,606			(649,285	)		91,638
Income tax benefit (expense)		(100,005	)		(102,392	)		(1,311	)
Net income (loss) from continuing operations		97,601			(751,677	)		90,327
Discontinued Operations: (Note 3)
Income (loss) before income taxes		(397,666	)		114,193			61,313
Income tax benefit (expense)		2,175			1,421			(308	)
Net income (loss) from discontinued operations		(395,491	)		115,614			61,005
Net income (loss)		(297,890	)		(636,063	)		151,332
Net income (loss) attributable to noncontrolling interest		(393,538	)		126,788			49,830
Net income (loss) attributable to Memorial Resource Development Corp.		95,648			(762,851	)		101,502
Net (income) loss allocated to members		—			(20,305	)		(90,712	)
Net (income) loss allocated to previous owners		—			(1,425	)		(10,790	)
Net (income) allocated to participating restricted stockholders		(734	)		—			—
Net (income) loss from discontinued operations		327			(314	)		—
Net income (loss) from continuing operations available to common stockholders	$	95,241		$	(784,895	)	$	—

Earnings per common share – basic: (Note 10)
Income (loss) from continuing operations	$	0.49		$	(4.08	)	$	—
Income (loss) from discontinued operations	$	—		$	—		$	—
Net income (loss)	$	0.49		$	(4.08	)	$	—

Earnings per common share – diluted: (Note 10)
Income (loss) from continuing operations	$	0.49		$	(4.08	)	$	—
Income (loss) from discontinued operations	$	—		$	—		$	—
Net income (loss)	$	0.49		$	(4.08	)	$	—

Weighted average common and common equivalent shares outstanding:
Basic		193,698			192,498			—
Diluted		193,698			192,498			—

	For the Year Ended
	December 31,
	2015			2014			2013
Cash flows from operating activities:
Net income (loss)	$	(297,890	)	$	(636,063	)	$	151,332
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
(Income) loss from discontinued operations		395,491			(115,614	)		(61,005	)
Depreciation, depletion, and amortization		188,742			128,238			70,903
Impairment of proved oil and natural gas properties		—			24,576			2,528
(Gain) loss on derivatives		(281,249	)		(257,438	)		(2,852	)
Cash settlements (paid) received on expired derivative instruments		170,899			8,866			7,725
Cash settlements on terminated derivatives		92,258			5,326			—
Premiums paid for derivatives		(46,152	)		(6,065	)		—
Loss on extinguishment of debt		—			30,248			—
Amortization of deferred financing costs		2,823			3,209			2,330
Accretion of senior notes net discount		—			580			50
Accretion of asset retirement obligations		417			533			593
Amortization of equity awards		8,788			2,804			—
(Gain) loss on sale of properties		(47	)		3,057			(82,773	)
Non-cash compensation expense		35,142			916,218			—
Deferred income tax expense (benefit)		89,935			101,778			76
Exploration costs		85			12,993			86
Changes in operating assets and liabilities:
Accounts receivable		(19,614	)		(7,419	)		(4,113	)
Prepaid expenses and other assets		9,529			(4,300	)		(4,280	)
Payables and accrued liabilities		64,131			8,469			7,872
Other		(546	)		5,694			—
Net cash provided by continuing operations		412,742			225,690			88,472
Net cash provided by discontinued operations		221,169			250,581			189,351
Net cash provided by operating activities		633,911			476,271			277,823
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(291,536	)		(93,909	)		(67,098	)
Additions to oil and gas properties		(594,901	)		(376,122	)		(185,194	)
Additions to other property and equipment		(3,853	)		(16,831	)		(2,307	)
Other financial instruments		(46,106	)		—			—
Deposits for property acquisitions		—			(215	)		—
Decrease (increase) in restricted cash		—			49,946			(49,347	)
Proceeds from the sale of oil and natural gas properties		13,612			6,700			151,187
Other		—			(301	)		—
Net cash used in continuing operations		(922,784	)		(430,732	)		(152,759	)
Net cash used in discontinued operations		(337,505	)		(1,386,247	)		(214,684	)
Net cash used in investing activities		(1,260,289	)		(1,816,979	)		(367,443	)
Cash flows from financing activities:
Advances on revolving credit facilities		798,000			1,300,800			174,400
Payments on revolving credit facilities		(558,000	)		(1,320,900	)		(200,500	)
Termination of second lien credit facility		—			(328,282	)		—
Proceeds from the issuance of senior notes		—			600,000			343,000
Redemption of senior notes		—			(351,808	)		—
Borrowings under second lien credit facility		—			—			325,000
Deferred financing costs		(1,498	)		(18,840	)		(20,251	)
Purchase of additional interests in consolidated subsidiaries		—			(3,292	)		(15,135	)
Proceeds from MRD equity offering		242,880			408,500			—
Costs incurred in conjunction with MRD equity offering		(4,773	)		(28,373	)		—
Proceeds from changes in ownership interests in MEMP		—			—			135,012
Contributions from NGP affiliates related to sale of assets		—			1,165			—
Distributions to the Funds		—			—			(732,362	)
Distribution to MRD Holdco		—			(59,803	)		—
Distributions to noncontrolling interests		—			(376	)		(7,446	)
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	)
MRD equity repurchases		(51,197	)		(161	)		—
Other		—			320			71
Net cash provided by (used in) continuing operations		425,412			99,487			(801	)
Net cash provided by discontinued operations		197,183			1,169,458			118,751
Net cash provided by financing activities		622,595			1,268,945			117,950
Net change in cash and cash equivalents		(3,783	)		(71,763	)		28,330
Add: cash balance included in assets of discontinued operations at beginning of period		2,594			26,191			32,336
Less: cash balance included in assets of discontinued operations at end of period		2,175			2,594			26,191
Cash and cash equivalents, beginning of period		3,364			51,530			17,055
Cash and cash equivalents, end of period	$	—		$	3,364		$	51,530

See Accompanying Notes to Consolidated and Combined Financial Statements. See Supplemental cash flow information (Note 2)

	Stockholders' Equity									Members' Equity
	Common stock			Additional paid in capital			Accumulated earnings (deficit)			Members			Previous Owners			Noncontrolling Interest			Total
Balance, December 31, 2012	$	—		$	—		$	—		$	811,614		$	233,433		$	231,662		$	1,276,709
Net income (loss)		—			—			—			90,712			10,790			49,830			151,332
Contributions		—			—			—			—			1,214			—			1,214
Net Proceeds from MEMP public equity offering		—			—			—			—			—			490,138			490,138
Sale of MEMP common units		—			—			—			60,701			—			74,311			135,012
Distributions		—			—			—			(732,362	)		(4,005	)		(78,083	)		(814,450	)
Net book value of net assets acquired from affiliates		—			—			—			50,751			(181,556	)		130,805			—
Amortization of MEMP equity awards		—			—			—			—			—			3,558			3,558
Noncontrolling interest's share of cash consideration received in excess of the net book value sold to MEMP		—			—			—			(24	)		—			24			—
Distribution to affiliate in connection with acquisition of assets		—			—			—			(98,180	)		—			(253,055	)		(351,235	)
Purchase of noncontrolling interests		—			—			—			(303	)		—			(14,832	)		(15,135	)
Impact of equity transactions of MEMP		—			—			—			54,183			—			(54,183	)		—
Other		—			—			—			94			(2,299	)		440			(1,765	)
Net assets retained by previous owners		—			—			—			—			(17,246	)		—			(17,246	)
Balance, December 31, 2013	$	—		$	—		$	—		$	237,186		$	40,331		$	580,615		$	858,132
Net income (loss)		—			—			(784,581	)		20,305			1,425			126,788			(636,063	)
Issuance of shares in connection with restructuring transactions (Note 1)		1,710			913,152			—			—			—			—			914,862
Issuance of shares in connection with initial public offering (Note 1)		215			379,962			—			—			—			—			380,177
Tax related effects in connection with restructuring transactions and initial public offering		—			(43,251	)		—			—			—			—			(43,251	)
Share repurchase		(1	)		—			(2,214	)		—			—			—			(2,215	)
Restricted stock awards		11			(11	)		—			—			—			—			—
Amortization of restricted stock awards		—			2,804			—			—			—			—			2,804
Contribution related to MRD Holdco incentive unit compensation expense (Note 12)		—			111,866			—			—			—			—			111,866
Purchase of noncontrolling interests		—			(2,881	)		—			—			—			(411	)		(3,292	)
Contribution related to sale of assets to NGP affiliate		—			—			—			1,165			—			—			1,165
Net book value of assets sold to NGP affiliate		—			—			—			(621	)		—			—			(621	)
Net book value of assets acquired from NGP affiliates		—			—			—			45,059			(41,756	)		—			3,303
Distribution to NGP affiliates in connection with acquisition of assets		—			—			—			(66,693	)		—			—			(66,693	)
Distribution of net assets to MRD Holdco		—			—			—			(123,078	)		—			29,994			(93,084	)
Distribution of shares received in connection with restructuring transactions to MRD Holdco		—			—			—			(110,510	)		—			—			(110,510	)
Net equity deemed contribution (distribution) related to net assets transferred to MEMP		—			5,327			—			(2,659	)		—			(2,668	)		—
Net proceeds from MEMP public equity offering		—			—			—			—			—			540,698			540,698
Distributions		—			—			—			—			—			(149,084	)		(149,084	)
Amortization of MEMP equity awards		—			—			—			—			—			7,874			7,874
MEMP common units repurchased		—			—			—			—			—			(12,903	)		(12,903	)
MEMP restricted units repurchased		—			—			—			—			—			(1,012	)		(1,012	)
Other		—			378			(76	)		(154	)		—			663			811
Balance, December 31, 2014	$	1,935		$	1,367,346		$	(786,871	)	$	—		$	—		$	1,120,554		$	1,702,964

	Stockholders' Equity
	Common stock			Additional paid in capital			Accumulated earnings (deficit)			Noncontrolling Interest			Total
Balance, December 31, 2014	$	1,935		$	1,367,346		$	(786,871	)	$	1,120,554			1,702,964
Net income (loss)		—			—			95,648			(393,538	)		(297,890	)
Issuance of shares in connection with equity offering		138			242,742			—			—			242,880
Cost incurred in conjunction with equity offering		—			(4,402	)		—			—			(4,402	)
Share repurchase		(28	)		—			(47,757	)		—			(47,785	)
Restricted stock awards		9			(9	)		—			—			—
Amortization of restricted stock awards		—			8,788			—			—			8,788
Contributions		—			—			—			2,962			2,962
Contribution related to MRD Holdco incentive unit compensation expense (Note 12)		—			35,142			—			—			35,142
Net equity deemed contribution (distribution) related to MEMP property exchange (Note 1)		—			(127,149	)		—			127,149			—
Deferred tax adjustments (Note 15)		—			38,778			—			—			38,778
Distributions		—			—			—			(163,007	)		(163,007	)
Subsidiary purchase of noncontrolling interests		—			—			—			(5,946	)		(5,946	)
Amortization of MEMP equity awards		—			—			—			10,809			10,809
MEMP common units repurchased		—			—			—			(53,999	)		(53,999	)
Restricted stock awards returned to plan		(1	)		—			(1,195	)		—			(1,196	)
Other		—			(287	)		—			110			(177	)
Balance, December 31, 2015	$	2,053		$	1,560,949		$	(740,175	)	$	645,094		$	1,467,921

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

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

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

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

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

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

Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item.

We have elected to early adopt new accounting pronouncements related to the presentation of deferred taxes and debt issuance costs. The retrospective adjustments to the December 31, 2014 balance sheet are shown below.

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

Prior to the sale of the Disposition Entities and its subsidiaries we had two reportable segments, one of which was MEMP and its subsidiaries. Effective June 1, 2016, we now have one reportable business segment, which is engaged in the acquisition, exploration, development and production of oil and natural gas properties. Accordingly, we have retrospectively revised our segment disclosures for all periods presented.

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

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

Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. Likewise, the combined financial statements include the accounts of our predecessor and the previous owners as discussed above. All material intercompany balances and transactions have been eliminated. Certain prior period balances have been reclassified to better align with financial statement presentation in the current fiscal year.

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

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

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

Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us, our predecessor, and the previous owners. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. We did not have any material write-offs related to uncollectible accounts during the years ended December 31, 2015, 2014 and 2013. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2015 and 2014, respectively.

If we were to lose any one of our customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified.

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

As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves.

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

There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2015, 2014, and 2013.

Oil and natural gas properties consisted of the following at the dates indicated:

At December 31, 2015 and 2014, we had $174.0 million and $100.5 million, respectively, capitalized in proved oil and natural gas properties related to wells in various stages of drilling and completion, which have been excluded from the depletion base.

The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, was engaged to audit our internally prepared reserves estimates at December 31, 2015.

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

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

An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized in net income (loss) to the extent the actual costs differ from the recorded liability. See Note 7 for further discussion of asset retirement obligations.

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Impairment expense for the years ended December 31, 2014 and 2013 was approximately $24.6 million and $2.5 million, respectively. We did not record any impairment expense for the year ended December 31, 2015. See Note 5 for further discussion on impairments.

These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2015, 2014, and 2013 was approximately $2.8 million, $3.2 million and $2.3 million, respectively.

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2015 or 2014.

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

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

Embedded derivatives that are required to be bifurcated and accounted for separately are treated in the same manner as freestanding derivatives. Embedded derivatives are recorded at fair value, with the difference between the basis of the hybrid financial instrument and the fair value of the embedded derivative recorded as the carrying value of the host contract. See Note 6 for further information on certain commodity contracts that required bifurcation.

We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included within intangible drilling costs and amortized using the units of production method. For the year ended December 31, 2015 and 2014, we capitalized $5.4 million and $4.5 million of interest, respectively.

The Company uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis in assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. The Company recognizes interest and penalties accrued to unrecognized tax benefits in other income (expense) in its consolidated statement of operations.

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 effective settlement with a taxing authority.

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

The fair value of equity-classified awards (e.g., restricted stock awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards (e.g., phantom unit awards) is recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. Generally, no compensation expense is recognized for equity instruments that do not vest.

Prior to the restructuring transactions, the governing documents of MRD LLC and certain of its subsidiaries provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date.

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

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

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

Balance Sheet Classification of Deferred Taxes. In November 2015, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update that requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendment. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The amendments may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We have adopted this guidance as of December 31, 2015 and applied the disclosure requirements retrospectively to the consolidated financial statements and footnote disclosure.

Simplifying the Accounting for Measurement-Period Adjustments. In September 2015, the FASB issued an accounting standards update that eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, an acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. Disclosure of the effect on earnings of any amounts an acquirer would have recorded in previous periods if the accounting had been completed at the acquisition date is required. The disclosure is required for each affected income statement line item, and may be presented separately on the face of the income statement or in the notes to the financial statements. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date and is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been issued. The Company does not expect the impact of adopting this guidance to be material to the Company’s financial statements and related disclosures.

Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. In August 2015, the FASB issued an accounting standards update that formally delayed the effective date of its new revenue recognition standard. The new standard is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Early adoption is now permitted for fiscal years, and interim periods within those years, beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Company beginning on January 1, 2018. The Company has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures.

Presentation of Debt Issuance Cost. In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company has chosen to adopt this standard and have applied this guidance in its consolidated financial statements and footnote disclosures.

In August 2015, the FASB issued an accounting standards update that incorporates SEC guidance clarifying that debt issuance costs related to line-of-credit arrangements can be deferred and presented as an asset that is subsequently amortized over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Company has elected this presentation in its consolidated financial statements and footnote disclosures as of December 31, 2015.

Amendments to Consolidation Analysis. In February 2015, the FASB issued an accounting standards update to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. Although the Company continues to assess the impact that adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures, we expect that MEMP will become a VIE. We believe we will continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements.

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

As previously discussed in Note 1, we sold the Disposition Entities and its subsidiaries on June 1, 2016 to MEMP. Below is a reconciliation of carrying amounts of major classes of assets and liabilities included as part of discontinued operations as reflected on the balance sheets associated with this disposal transaction (in thousands):

	December 31,		December 31,
	2015		2014
ASSETS
Current assets:
Cash and cash equivalents	$	2,175	$	2,594
Accounts receivable		61,403		98,498
Short-term derivative instruments		272,320		208,585
Prepaid expenses and other current assets		9,643		11,859
Total current assets		345,541		321,536
Property and equipment, net		1,946,937		2,471,011
Long-term derivative instruments		461,809		311,802
Restricted investments		152,631		77,361
Other long-term assets		5,053		5,062
Total assets	$	2,911,971	$	3,186,772

LIABILITIES
Current liabilities:
Accounts payable	$	8,792	$	24,813
Accounts payable - affiliates		193		464
Revenues payable		27,021		35,545
Accrued liabilities		52,923		95,835
Short-term derivative instruments		2,850		3,289
Total current liabilities		91,779		159,946
Long-term debt		2,000,579		1,574,147
Asset retirement obligations		162,989		112,702
Long-term derivative instruments		1,441		—
Deferred tax liabilities		2,094		32,347
Total liabilities	$	2,258,882	$	1,879,142

Below is a reconciliation of major line items constituting pretax profit (loss) of discontinued operations to the after tax profit (loss) of discontinued operations that are presented in the statement of operations (in thousands):

	For Year Ended December 31,
	2015			2014			2013
Revenues:
Oil & natural gas sales	$	355,422		$	561,677		$	391,440
Other revenues		2,725			4,366			3,075
Total revenues		358,147			566,043			394,515

Costs and expenses:
Lease operating		168,199			143,733			94,591
Gathering, processing, and transportation		34,939			31,892			25,055
Exploration		2,317			2,750			1,322
Taxes other than income		25,828			33,141			18,447
Depreciation, depletion, and amortization		195,814			185,955			113,814
Impairment of proved oil and natural gas properties		616,784			407,540			4,072
General and administrative (1)		56,671			49,124			54,947
Accretion of asset retirement obligations		7,125			5,773			4,988
(Gain) loss on commodity derivative instruments		(462,890	)		(492,254	)		(26,133	)
(Gain) loss on sale of properties		(2,998	)		—			(2,848	)
Other, net		(665	)		(11	)		647
Total costs and expenses		641,124			367,643			288,902
Operating income (loss)		(282,977	)		198,400			105,613
Other income (expense):
Interest expense, net		(114,732	)		(83,550	)		(44,302	)
Other, net		43			(657	)		2
Total other income (expense)		(114,689	)		(84,207	)		(44,300	)
Pretax profit (loss) of discontinued operations		(397,666	)		114,193			61,313
Income tax benefit (expense)		2,175			1,421			(308	)
Net income (loss) from discontinued operations	$	(395,491	)	$	115,614		$	61,005

The third party acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, we, our predecessor, and the previous owners conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while acquisition costs associated with the acquisitions were expensed as incurred. The operating revenues and expenses of acquired properties are included in the accompanying financial statements from their respective closing dates forward. The transactions were financed through equity offerings, capital contributions and borrowings under credit facilities.

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

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

On June 1, 2015, we entered into an oil and gas lease option agreement with a third party pursuant to which we have the right to obtain one or more oil and gas leases in North Louisiana and is exercisable through February 2017. The purchase price of this option

was approximately $4.0 million. The purchase price has been capitalized as part of unproved properties and will be expensed if the option is not exercised.

On October 22, 2015, we closed a transaction to acquire certain proved and unproved oil and natural gas properties in North Louisiana from a third party for approximately $284.3 million (the “North Louisiana Acquisition”), of which $281.9 million of the purchase price was allocated to unproved oil and natural gas properties with the remainder allocated to proved oil and natural gas properties.

On April 17, 2015, we sold certain oil and natural gas properties in Colorado and Wyoming to a third party for approximately $13.6 million (the “Rockies Divestiture”) and recorded a gain of less than $0.1 million related to the sale.

On December 30, 2014, we acquired certain oil and natural gas producing properties from third parties in the Terryville Complex for approximately $71.9 million, after customary post-closing adjustments (the “Louisiana Acquisition”). The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands):

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

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

On April 30, 2013, WildHorse Resources purchased certain oil and gas properties and leases in Louisiana from a third party for approximately $67.1 million. The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands):

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

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

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:

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

Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. At December 31, 2015 and 2014, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.

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

The carrying values of cash and cash equivalents, accounts receivables, other financial assets, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at December 31, 2015 and December 31, 2014. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 8 for the estimated fair value of our outstanding fixed-rate debt.

The fair market values of the derivative financial instruments reflected on the balance sheets as of December 31, 2015 and December 31, 2014 were based on estimated forward commodity prices (including nonperformance risk) and forward interest rate yield curves. Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2015 and December 31, 2014 for each of the fair value hierarchy levels:

Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values:

Derivative and other financial instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These transactions limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease.

Certain inherent business risks are associated with commodity and interest derivative contracts and other financial instruments, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, and other financial instruments only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreements are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative and other financial instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative or other financial instrument, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative and other financial asset receivables from the defaulting party. At December 31, 2015, we had derivative and other financial assets of $365.4 million. After taking into effect netting arrangements, we had counterparty exposure of $169.1 million related to derivative and other financial instruments of which $86.8 million was with a single counterparty. Had certain counterparties failed completely to perform according to the terms of their existing contracts, we would have the right to offset $196.3 million against amounts outstanding under our revolving credit facility at December 31, 2015. See Note 8 for additional information regarding our revolving credit facility.

We may use a combination of commodity derivatives and other financial instruments (e.g., floating-for-fixed swaps, put options, costless collars and basis swaps) to manage exposure to commodity price volatility. We recognize all derivative instruments at fair value; however, certain of our put option derivative instruments have a deferred premium, which reduces the asset. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement. At settlement, if the applicable index price is below the strike price of the put, the Company receives the difference between the strike price and the applicable index price multiplied by the contract volumes less the premium. If the applicable index price settles at or above the strike price of the put, the Company pays only the premium at settlement. Cash settlements received on settled derivative positions during 2015 is net of deferred premiums of $8.0 million.

During the year ended December 31, 2015, we restructured our existing 2018 crude oil and natural gas hedges for crude oil and NGL swaps that will settle in 2016. Cash settlements of approximately $92.3 million from the terminated 2018 positions were received and applied as premiums for the new crude oil and NGL swaps. Certain contracts are classified as other financial instruments, which require bifurcation, based on the relationship between the fixed swap price and the market price at the restructure dates. Due to bifurcation, $46.1 million of the restructured contracts represents other financial assets at December 31, 2015.

During the year ended December 31, 2014, we restructured a portion of our commodity derivative portfolio by terminating “in the money” natural gas collars settling in 2015 and entering into natural gas swaps. The cash settlement receipts of $6.1 million from the termination of the collars were utilized to enhance the fixed price portion of the natural gas swaps.

We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub and regional indices such as TGT Z1 in proximity to our areas of production. Our oil derivative contracts are primarily indexed to NYMEX-WTI. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu.

At December 31, 2015, we had the following open commodity positions (excluding embedded derivatives):

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

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

Purchased put option contracts:
Average Monthly Volume (MMBtu)		6,000,000			5,350,000
Weighted-average strike price	$	3.51		$	3.48
Weighted-average deferred premium paid	$	(0.34	)	$	(0.32	)

TGT Z1 basis swaps:
Average Monthly Volume (MMBtu)		1,120,000			200,000
Spread - Henry Hub	$	(0.10	)	$	(0.08	)

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		35,583			28,000
Weighted-average fixed price	$	83.58		$	84.70

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

NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		353,399			—
Weighted-average fixed price	$	39.68		$	—

Periodically, interest rate swaps are entered into to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our revolving credit agreement to fixed interest rates. On July 1, 2014, we elected to terminate the interest rate swaps associated with our credit facility and in the aggregate paid our counterparties approximately $0.7 million. WildHorse Resources novated the interest rate swaps to MRD in connection with the closing of our initial public offering. We did not have any interest rate swaps at December 31, 2015.

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2015 and 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain affiliates, to our derivative contracts are lenders under our credit agreement.

All gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations since derivative instruments are not designated as hedging instruments for accounting and financial reporting purposes. The following table details the gains and losses related to derivative instruments for the years ending December 31, 2015, 2014, and 2013:

Asset retirement obligations primarily relate to our portion of future plugging and abandonment of wells and related facilities. The following table presents the changes in the asset retirement obligations for the years ended December 31, 2015, 2014 and 2013:

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

On June 18, 2014, we, as borrower, and certain of our subsidiaries, as guarantors, entered into a revolving credit facility, which is a five-year, $2.0 billion revolving credit facility.

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

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

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

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

Events of default under the revolving credit facility include, but are not limited to, failure to make payments when due, breach of any covenant continuing beyond the applicable cure period, default under any other material debt, change in management or change of control, bankruptcy or other insolvency event and certain material adverse effects on our business.

On July 10, 2014, we completed a private placement of $600.0 million aggregate principal amount of 5.875% senior unsecured notes (the “MRD Senior Notes”) at par. The MRD Senior Notes will mature on July 1, 2022. Interest on the MRD Senior Notes will accrue from July 10, 2014 and will be payable semiannually on January 1 and July 1 of each year, commencing on January 1, 2015. The MRD Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing subsidiaries (subject to customary release provisions). The MRD Senior Notes and the guarantees of the MRD Senior Notes will rank equally with our and the guarantors’ existing and future senior indebtedness, will be effectively junior to all of our and the guarantors’ existing and future secured indebtedness (to the extent of the value of the assets securing such indebtedness), and senior in right of payment to all of our and the guarantors’ subordinated indebtedness. The MRD Senior Notes will be structurally subordinated to the indebtedness and other liabilities of our non-guarantor subsidiaries. Effective June 1, 2016, the guarantor subsidiaries are 100% owned by the Company; the Company has no material assets or operations independent of the guarantor subsidiaries; and there are no significant restrictions upon the ability of the guarantor subsidiaries to distribute funds to the Company.

The MRD Senior Notes are governed by an indenture dated as of July 10, 2014. The MRD Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any, to the date of redemption. The Company may also be required to repurchase the MRD Senior Notes upon a change of control. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the MRD Senior Notes receive an investment grade rating from both of two specified ratings agencies. MEMP and its subsidiaries are not subject to these covenants. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either the Company or the guarantors, all outstanding MRD Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding MRD Senior Notes may declare all the MRD Senior Notes to be due and payable immediately.

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

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

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

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

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

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

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

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

The Company’s authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares since January 1, 2014:

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

On September 25, 2015, the Company issued 13,800,000 shares of common stock (including 1,800,000 shares of common stock sold pursuant to the full exercise of the underwriters’ option to purchase additional shares of common stock) to the public generating total net proceeds of approximately $238.1 million after deducting underwriting discounts and offering expenses. The net proceeds from the equity offering were used to temporarily pay down our revolving credit facility and subsequently re-borrowed to fund a portion of the purchase price of the North Louisiana Acquisition that closed on October 22, 2015.

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

We repurchased 2,764,887 shares of common stock under our repurchase program for an aggregate price of $47.8 million through March 16, 2015, which exhausted the December 2014 repurchase program. We have retired all of the shares of common stock repurchased and the shares of common stock are no longer issued or outstanding.

In April 2015, the Board authorized the repurchase of up to $50.0 million of the Company’s outstanding common stock from time to time on the open market, through block trades or otherwise. The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program, which may be suspended or discontinued at any time. The amount, timing and price of purchases will depend on market conditions and other factors. The Company did not repurchase any shares of common stock under this program through December 31, 2015.

Our amended and restated certificate of incorporation authorizes our Board, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50,000,000 shares of preferred stock. There are no shares of preferred stock issued and outstanding as of December 31, 2015.

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

Noncontrolling interests is the portion of equity ownership in the Company’s consolidated subsidiaries not attributable to the Company and primarily consists of the equity interests held by the limited partners of MEMP. Prior to our initial public offering, certain current or former key employees of certain of MRD LLC’s subsidiaries also held equity interests in those subsidiaries.

Distributions paid to the limited partners of MEMP primarily represent the quarterly cash distributions paid to MEMP’s unitholders, excluding those paid to MRD LLC prior to our initial public offering. Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings. These distributions and contributions are a component of net cash provided by discontinued operations from financing activities as presented on our cash flow statement.

On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to MRD LLC and all incentive units held were forfeited. See Note 12 for further information. In connection with this sale, all of Tanos’ employees resigned and became employees of Tanos Exploration II, LLC (“Tanos II”), a Texas limited liability company controlled by the former management team of Tanos. Effective April 1, 2013, Tanos II entered into a transition services agreement with Tanos, whereby Tanos II would manage the operations of Tanos for up to a 6-month period of time. Tanos II is an unrelated entity.

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

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

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

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

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

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

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

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

The unrecognized compensation cost associated with restricted common share awards was an aggregate $25.1 million at December 31, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.42 years.

Subsequent event. An award of 8,023 shares of restricted stock was granted to each of our independent directors on January 8, 2016 and will vest one year from the date of grant.

Each of the governing documents of BlueStone, Tanos, WildHorse Resources, Classic, Black Diamond and MRD LLC previously provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date.

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

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

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

On November 1, 2013, MRD LLC purchased the noncontrolling interests in Black Diamond, Classic GP and Classic and all incentive units were forfeited. Compensation expense of approximately $12.6 million was recorded by Black Diamond, Classic GP and Classic in the aggregate during November 2013, of which $8.3 million is reflected as a component of discontinued operations.

Compensation expense of approximately $1.0 million and $20.7 million was recorded by BlueStone and recognized as a component of incentive unit compensation expense during the year ended December 31, 2014 and 2013, respectively.

In connection with the PIK notes issued in December 2013, a special distribution of $10.0 million to holders of WildHorse’s Tier 1 incentive units was deemed probable of occurring. This amount was recognized as compensation expense in December 2013.

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

MRD LLC incentive units were originally granted in June 2012 and February 2013. In connection with our initial public offering and the related restructuring transactions, these incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. MRD Holdco’s governing documents authorize the issuance of 1,000 incentive units, of which 930 incentive units were granted in an exchange for the cancelled MRD LLC awards (the “Exchanged Incentive Units”). Subsequent to our initial public offering, MRD Holdco granted the remaining 70 incentive units to certain key employees (the “Subsequent Incentive Units”).

We recognized $35.2 million and $111.9 million of compensation expense in 2015 and 2014, respectively, offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $58.8 million as of December 31, 2015 will be recognized over the remaining expected service period of 1.42 years.

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

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

Amounts due to MRD Holdco and certain affiliates of NGP at December 31, 2015 and 2014 are presented as “Accounts payable – affiliates” in the accompanying balance sheets.

During the year ended December 31, 2015, we paid approximately $8.5 million to Cretic Energy Services, LLC, an NGP affiliated company, for services related to our drilling and completion activities.

During the year ended December 31, 2015, we paid approximately $2.3 million to Multi-Shot, LLC, an NGP affiliated company, for services related to our drilling and completion activities, of which $0.3 million was attributable to discontinued operations.

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

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

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

WildHorse Resources repurchased the net profits interests discussed above from NGPCIF on February 28, 2014 for a purchase price of $63.4 million (see Note 1). This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. WildHorse Resources recorded the following net assets (in thousands):

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

The previous owners sold certain interests in oil and gas properties offshore Louisiana on October 11, 2012. The remaining proceeds of approximately $2.0 million were released from escrow in April 2013, which is reflected as a component of net cash provided by discontinued operations from financing activities as presented on our cash flow statement.

On October 1, 2013, MEMP acquired, through equity and asset transactions, oil and natural gas properties primarily in the Permian Basin, East Texas and the Rockies from MRD LLC and certain affiliates of NGP for an aggregate purchase price of approximately $603 million (subject to customary post-closing adjustments), of which $507.1 million was received by certain affiliates of NGP and included as a component of discontinued operation on the statement of cash flows. We refer to this transaction as the “Cinco Group acquisition.” The Cinco Group acquisition was funded with borrowings under MEMP’s revolving credit facility, which is also included in discontinued operations. The Cinco Group acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. The net assets acquired were as follows (in thousands):

On November 2, 2015, in connection with an auction process administered by a third-party, MEMP divested certain oil and gas properties in the Permian Basin to an affiliate of NGP for a purchase price of approximately $0.9 million. Due to common control considerations, the proceeds from the sale exceeded the net book value of the properties by $0.7 million and is recognized as a contribution in the equity statement.

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

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

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

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

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

In connection with the closing of our initial public offering, we entered into a voting agreement with MRD Holdco, WHR Incentive LLC, a limited liability company beneficially owned by Messrs. Bahr and Graham, and certain former management members of WildHorse Resources, including Graham, who contributed their ownership of WildHorse Resources to us in the restructuring transactions. Among other things, the voting agreement provides that Graham and those former management members of WildHorse Resources will vote all of their shares of our common stock as directed by MRD Holdco.

The voting agreement also provides MRD Holdco with the right to designate up to three nominees to the Board, provided that such number of nominees shall be reduced to two, one and zero if the Funds and their affiliates collectively own less than 35%, 15%, and 5% respectively, of the outstanding shares of our common stock. The voting agreement also requires us and the stockholders party thereto to take all necessary actions, to the fullest extent permitted by applicable law (including with respect to any fiduciary duties under Delaware law), including voting their shares of our common stock, to cause the election of the nominees designated by MRD Holdco. In addition, the voting agreement provides that for so long as MRD Holdco has the right to designate two directors to the Board, we will cause any committee of the Board to include in its membership at least one director designated by MRD Holdco, except to the extent that such membership would violate applicable securities laws or stock exchange rules.

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

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

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

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

Certain of the Cinco Group entities entered into advisory service, reimbursement, and indemnification agreements with NGP. These agreements generally required that an annual advisory fee be paid to NGP. Fees paid under these agreements for the year ended December 31, 2013 were approximately $0.3 million.

Prior to our initial public offering, we entered into various midstream service agreements with affiliates of PennTex Midstream Partners, LP (“PennTex”), an affiliate of NGP, for the gathering, processing and transportation of natural gas and NGLs. Additionally, we entered into an area of mutual interest and exclusivity agreement (“AMI”) with PennTex pursuant to which PennTex has the exclusive right to provide midstream services to support our current and future production in North Louisiana on our operated acreage within such area (other than production subject to existing third-party commitments).

PennTex is a publicly traded master limited partnership. MRD Midstream LLC (“MRD Midstream”), a wholly-owned subsidiary of MRD Holdco, has ownership interests in both PennTex and its general partner. In addition to a 5.25% membership interest in PennTex’s general partner, MRD Midstream also owns approximately 18.4% of PennTex’s limited partner interests and 5.25% of its incentive distribution rights.

The amended and restated gas processing agreement, (“GPA”) has a 15-year primary term, subject to one-year extensions at either party’s election. Processing fees under the GPA are subject to annual inflation escalators. Under the GPA, the Company has agreed to deliver a minimum volume of gas for processing through the term of the agreement measured on a cumulative basis based on specified daily minimum volume thresholds. Any volumes of gas delivered up to the then-applicable daily minimum volume threshold are considered firm reserved gas and are charged the firm fixed-commitment fee, and any volumes delivered in excess of such threshold are considered interruptible volumes and are charged the interruptible-service fixed fee. Pursuant to the GPA, any deficiency payments made by the Company under the GPA will be treated as prepaid processing fees by PennTex (except for the June 2015 deficiency payment). These charges do not expire until the end of the primary term of the GPA. Quarterly deficiency payments are based on the firm-commitment fixed fee. The following table summarizes the minimum volume commitment (“MVC”) and fees associated with the GPA.

The gas gathering agreement, as amended, (“GGA”) has a 15-year primary term, subject to one-year extensions at either party’s election. The Company pays fees for gathering services provided by PennTex, including a firm capacity reservation payment through November 30, 2019 and a usage fee component that is subject to a minimum volume commitment. The GGA also has an annual “use it or lose it” deficiency provision that is based on the usage fee. The minimum volume commitment under the GGA is linked to the minimum volume commitment under the GPA.

The gas transportation agreement, as amended, (“GTA”) has a 15-year primary term, subject to one-year extensions at either party’s election. The GTA provides for the transportation of residue gas through PennTex’s residue gas pipeline from the outlet of their processing plants to delivery points at interconnections with third-party natural gas transportation pipelines. The Company pays a usage fee for all volumes transported under the GTA. The GTA includes a plant tailgate dedication pursuant to which all of the Company’s residue gas produced from the PennTex’s processing plants are delivered for transportation on their residue gas pipeline. The GTA also includes a fixed monthly demand charge to provide priority firm service. The following table summarizes the fees associated with the GTA:

The transportation services agreement (“TSA”) provides for the transportation of NGLs through PennTex’s NGL pipeline from the outlet of their processing plants to a third party delivery point. The Company pays a usage fee for all volumes transported under the TSA. The TSA includes a plant tailgate dedication pursuant to which all of the Company’s NGLs produced from PennTex’s processing plants are delivered for transportation on the its NGL pipeline. The following table summarizes the fees associated with the TSA:

All net costs associated with these agreements are reflected in the statement of operations in the “Gathering processing, and transportation – affiliate” line.

On November 1, 2011, Classic Hydrocarbons Operating, LLC (“Classic Operating”), which became our wholly-owned subsidiary in connection with the restructuring transactions, and Classic Pipeline entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. On May 1, 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed, and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement had a term until December 31, 2023, subject to one-year extensions at either party’s election. The amended gas gather agreement was terminated in November 2015 in connection with a third party’s acquisition of Classic Pipeline’s Joaquin gathering system.

On May 1, 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement had a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline. Effective July, 1 2015, the fee was reduced to $0.40 per barrel for each barrel of water delivered to Classic Pipeline.

In February 2015, Classic sold all of the equity interests owned by it in Classic Operating to Memorial Production Operating LLC (“OLLC”), a wholly-owned subsidiary of MEMP, and Classic and Classic GP were merged into MRD Operating in March 2015.

Classic Pipeline assigned its saltwater disposal system to OLLC in November 2015. Due to common control considerations, we recorded the receipt of this asset at historical cost and recognized approximately $2.1 million as a contribution in the equity statement.

For the years ended December 31, 2015, 2014 and 2013, MEMP incurred gathering and salt water disposal fees of approximately $3.6 million, $1.8 million and $0.6 million, respectively, from Classic Pipeline, an affiliate. These fees are a component of net income (loss) from discontinued operations as presented on our statement of operations.

The components of income tax benefit (expense) from continuing operations are as follows:

The actual income tax benefit (expense) from continuing operations differs from the expected amount computed by applying the federal statutory corporate tax rate of 35% as follows:

In June 2014, we recorded a deferred tax liability of approximately $43.3 million through stockholders’ equity in connection with our initial public offering and the related restructuring transactions. The tax basis of our assets and liabilities were stepped up as a result of our initial public offering and the related restructuring transactions, which is reported as a transaction among stockholders for financial reporting purposes.

Consistent with establishing the deferred tax liability through stockholders’ equity in our initial public offering, we reversed a deferred tax liability of approximately $38.8 million through stockholders’ equity in 2015, of which $4.4 million was associated with the estimated deferred tax effects included in equity in connection with our initial public offering in 2014 and $34.4 million was attributable to the deferred tax effects of a common control transaction with MEMP in February 2015.

Uncertain Income Tax Position. We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. We had no unrecognized tax benefits as of December 31, 2015 and expect no significant change to the unrecognized tax benefits over the next twelve months ending December 31, 2016.

Tax Audits and Settlements. Generally, our income tax years 2011 through 2015 remain open and subject to examination by Federal tax authorities or the tax authorities in Louisiana and Texas and certain other small state taxing jurisdictions where we conduct operations. In certain jurisdictions we operate through more than one legal entity, each of which may have different open years subject to examination.

Tax Attribute Carryforwards and Valuation Allowance. As of December 31, 2015, we had federal net operating loss carryforwards of approximately $169.5 million, of which $0.2 million is a component of discontinued operations, which would expire in 2034 and 2035. We also had state tax carryforwards of approximately $173.6 million, which would expire 2034 and 2035. No valuation allowance was established based upon management’s evaluation that loss carryforwards will be fully realized. We had alternative minimum tax credit carryfowards of approximately $10.0 million, which would be carried forward indefinitely.

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

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

The following table presents the activity of our environmental reserves for the years ended December 31, 2014 and 2013:

Our environmental reserves were classified as current liabilities in accrued liabilities for the periods presented.

We have an existing amended and restated midstream service agreement with Regency Field Services LLC (“Regency”) for the gathering and processing of natural gas in in North Louisiana. The agreement’s primary term expires on December 31, 2025, subject to one-year extensions at either party’s election. Pursuant to the agreement, Regency expanded its Dubach processing facility among other facility and infrastructure improvements, built a new high pressure gathering pipeline to tie-in to their Dubberly processing plant amongst other pipeline and infrastructure improvements, and constructed facilities that permit deliveries into PennTex’s system (see Note 13). Regency is entitled to receive a payback demand fee from us and other third parties equal to 110% of the infrastructure improvement costs. The payback demand fee is based upon actual volumes gathered, but not less than a specified monthly demand quantity. Until payout is achieved, there is also a monthly demand quantity associated with gathering and processing fees. The table below summarizes the monthly demand quantity (“MDQ”) and fees associated with the agreement. Based on the MDQ, we project that that payout would be achieved during January 2020.

Regency has no obligation to process gas gathered and dedicated under the agreement after December 31, 2020. Effective on January 1, 2021 and continuing through the termination or expiration of the agreement, we will deliver all gas from the dedicated area and Regency will gather such gas, but will only process gas upon request. We have the right to request that gas gathered by Regency be delivered to alternative delivery points for processing (e.g., PennTex). Under these circumstances, Regency assesses us a $0.25 per MMBtu gathering only fee to take gas off its system.

See Note 13 for additional information related to the Classic and PennTex agreements.

We also have leases for our corporate headquarters, lease equipment and incur surface rentals related to our business operations. For the years ended December 31, 2015, 2014, and 2013, we recognized $8.5 million, $3.9 million, and $3.0 million of rent expense, respectively.

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

The following tables present selected quarterly financial data for the periods indicated. Earnings per share are computed independently for each of the quarters presented and the sum of the quarterly earnings per share may not necessarily equal the total for the year. As discussed in Note 12, we recorded incentive unit compensation expense, respectively, during 2014 and 2015, which impacted the comparability of net income (loss) from continuing operations between the periods presented below.

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
For the Year Ended December 31, 2015	(In thousands, except per share amounts)
Revenues	$	87,023		$	78,605		$	111,654		$	96,760
Operating income (loss)		107,872			(41,593	)		120,415			51,330
Net income (loss) from continuing operations		50,509			(26,614	)		56,726			16,980
Net income (loss)		(112,149	)		(140,473	)		(135,255	)		89,987
Net income (loss) attributable to noncontrolling interest		(158,041	)		(113,771	)		(191,807	)		70,081
Net income (loss) attributable to Memorial Resource Development Corp.		45,892			(26,702	)		56,552			19,906
Net income (loss) from continuing operations available to common stockholders		45,615			(26,702	)		56,051			20,277
Earnings per common share – basic
Income (loss) from continuing operations		0.24			(0.14	)		0.29			0.10
Income (loss) from discontinued operations		0.24			(0.14	)		0.29			0.10
Earnings per common share – diluted
Income (loss) from continuing operations		0.24			(0.14	)		0.29			0.10
Income (loss) from discontinued operations		0.24			(0.14	)		0.29			0.10

	First Quarter			Second Quarter			Third Quarter		Fourth Quarter
For the Year Ended December 31, 2014	(In thousands, except per share amounts)
Revenues	$	87,736		$	110,569		$	99,035	$	111,742
Operating income (loss)		27,344			(899,962	)		47,123		263,421
Net income (loss) from continuing operations		9,376			(941,803	)		10,730		170,020
Net income (loss)		(23,516	)		(1,053,443	)		112,037		328,859
Net income (loss) attributable to noncontrolling interest		(31,888	)		(105,094	)		102,109		161,661
Net income (loss) attributable to Memorial Resource Development Corp.		8,372			(948,349	)		9,928		167,198
Net income (loss) allocated to members		6,947			13,358			—		—
Net income (loss) allocated to previous owners		1,425			—			—		—
Net income (loss) from continuing operations available to common stockholders	n/a				(961,707	)		9,928		166,884
Earnings per common share – basic
Income (loss) from continuing operations	n/a				(5.00	)	0.05			0.87
Income (loss) from discontinued operations	n/a				(5.00	)	0.05			0.87
Earnings per common share – diluted
Income (loss) from continuing operations	n/a				(5.00	)	0.05			0.87
Income (loss) from discontinued operations	n/a				(5.00	)	0.05			0.87

The following supplemental information has been retrospectively revised to exclude amounts for all periods presented related to discontinued operations.

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

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

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

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

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

Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

We engaged NSAI to audit our internally prepared reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2015. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.

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

The following tables set forth estimates of the net reserves as of December 31, 2015, 2014, and 2013 respectively:

	For the Year Ended December 31, 2015
	Oil (MBbls)			Gas (MMcf)			NGLs (MBbls)			Equivalent (MMcfe)
Proved developed and undeveloped reserves:
Beginning of the year		11,915			1,013,340			53,033			1,403,030
Extensions and discoveries		1,111			50,343			2,741			73,456
Purchase of minerals in place		535			17,508			969			26,532
Production		(1,331	)		(98,269	)		(3,249	)		(125,749	)
Sales of minerals in place		(407	)		(39,272	)		(358	)		(43,861	)
Revision of previous estimates		1,331			30,164			1,024			44,286
End of year		13,154			973,814			54,160			1,377,694

Proved developed reserves:
Beginning of year		3,708			355,331			18,203			486,793
End of year		6,101			443,983			24,583			628,081

Proved undeveloped reserves:
Beginning of year		8,207			658,009			34,830			916,237
End of year		7,053			529,831			29,577			749,613

	For the Year Ended December 31, 2014
	Oil (MBbls)			Gas (MMcf)			NGLs (MBbls)			Equivalent (MMcfe)
Proved developed and undeveloped reserves:
Beginning of the year		10,824			671,485			35,628			950,199
Extensions and discoveries		1,825			183,467			9,876			253,670
Purchase of minerals in place		269			22,186			1,247			31,283
Production		(908	)		(56,574	)		(1,863	)		(73,200	)
Sales of minerals in place		(623	)		(10,815	)		(950	)		(20,253	)
Revision of previous estimates		528			203,591			9,095			261,331
End of year		11,915			1,013,340			53,033			1,403,030

Proved developed reserves:
Beginning of year		3,238			223,362			12,226			316,154
End of year		3,708			355,331			18,203			486,793

Proved undeveloped reserves:
Beginning of year		7,586			448,123			23,402			634,045
End of year		8,207			658,009			34,830			916,237

	For the Year Ended December 31, 2013
	Oil (MBbls)			Gas (MMcf)			NGLs (MBbls)			Equivalent (MMcfe)
Proved developed and undeveloped reserves:
Beginning of the year		10,220			549,449			31,264			798,357
Extensions and discoveries		1,635			105,289			5,712			149,369
Purchase of minerals in place		211			31,815			1,017			39,183
Production		(631	)		(28,729	)		(1,282	)		(40,212	)
Sales of minerals in place		(599	)		(14,137	)		(1,573	)		(27,169	)
Revision of previous estimates		(12	)		27,798			490			30,671
End of year (1)		10,824			671,485			35,628			950,199

Proved developed reserves:
Beginning of year		2,813			180,523			10,208			258,651
End of year		3,238			223,362			12,226			316,154

Proved undeveloped reserves:
Beginning of year		7,407			368,926			21,056			539,706
End of year		7,586			448,123			23,402			634,045

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

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

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

The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2015:

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

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

	As of December 31, 2015
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2,986	$	—	$	—	$	(2,986	)	$	—
Accounts receivable - trade		7,850		48,372		—		(3,530	)		52,692
Accounts receivable - affiliates		9,525		—		—		(9,525	)		—
Short-term derivative instruments		227,991		—		—		—			227,991
Other financial assets		46,106		—		—		—			46,106
Prepaid expenses and other current assets		2,318		1,056		—		—			3,374
Assets of discontinued operations		—		3,779		340,186		1,576			345,541
Total current assets		296,776		53,207		340,186		(14,465	)		675,704
Property and equipment, net		15,825		1,728,622		—		—			1,744,447
Long-term derivative instruments		91,292		—		—		—			91,292
Investments in subsidiaries		1,482,847		—		—		(1,482,847	)		—
Other long-term assets		4,976		—		—		—			4,976
Assets of discontinued operations		—		614		2,565,816		—			2,566,430
Total assets	$	1,891,716	$	1,782,443	$	2,906,002	$	(1,497,312	)	$	5,082,849

LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	26,796	$	66,133	$	—	$	1,004		$	93,933
Accounts payable - affiliates		—		17,339		—		(12,323	)		5,016
Revenues payable		80		33,946		—		—			34,026
Liabilities of discontinued operations		—		1,517		93,408		(3,146	)		91,779
Total current liabilities		26,876		118,935		93,408		(14,465	)		224,754
Long-term debt		1,012,064		—		—		—			1,012,064
Asset retirement obligations		—		10,079		—		—			10,079
Deferred tax liabilities		22,754		170,979		—		—			193,733
Other long-term liabilities		7,195		—		—		—			7,195
Liabilities of discontinued operations		—		—		2,167,103		—			2,167,103
Total liabilities		1,068,889		299,993		2,260,511		(14,465	)		3,614,928
Equity:
Equity		822,827		1,482,450		645,491		(2,127,941	)		822,827
Noncontrolling interest		—		—		—		645,094			645,094
Total equity		822,827		1,482,450		645,491		(1,482,847	)		1,467,921
Total liabilities & equity	$	1,891,716	$	1,782,443	$	2,906,002	$	(1,497,312	)	$	5,082,849

	As of December 31, 2014
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2,241	$	1,123	$	—	$	—		$	3,364
Accounts receivable- trade		5,995		29,804		—		(2,721	)		33,078
Accounts receivable - affiliates		10,047		—		—		(10,047	)		—
Short-term derivative instruments		131,471		—		—		—			131,471
Prepaid expenses and other current assets		4,178		7,166		—		—			11,344
Assets of discontinued operations		—		18,614		303,961		(1,039	)		321,536
Total current assets		153,932		56,707		303,961		(13,807	)		500,793
Property and equipment, net		16,601		1,050,043		—		—			1,066,644
Long-term derivative instruments		123,567		—		—		—			123,567
Investments in subsidiaries		1,139,792		—		—		(1,139,792	)		—
Other long-term assets		3,324		260		—		2			3,586
Assets of discontinued operations		—		679		2,864,559		(2	)		2,865,236
Total assets	$	1,437,216	$	1,107,689	$	3,168,520	$	(1,153,599	)	$	4,559,826

LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable and accrued expenses	$	6,245	$	49,075	$	—	$	(3,125	)	$	52,195
Accounts payable - affiliates		—		160		—		—			160
Revenues payable		—		21,807		—		—			21,807
Liabilities of discontinued operations		—		16,384		152,985		(9,423	)		159,946
Total current liabilities		6,245		87,426		152,985		(12,548	)		234,108
Long-term debt		770,545		—		—		—			770,545
Asset retirement obligations		—		9,829		—		—			9,829
Deferred tax liabilities		69,431		45,122		—		46			114,599
Other long-term liabilities		8,585		—		—		—			8,585
Liabilities of discontinued operations		—		1		1,719,241		(46	)		1,719,196
Total liabilities		854,806		142,378		1,872,226		(12,548	)		2,856,862
Equity:
Equity		582,410		965,311		1,290,734		(2,256,045	)		582,410
Noncontrolling interest		—		—		5,560		1,114,994			1,120,554
Total equity		582,410		965,311		1,296,294		(1,141,051	)		1,702,964
Total liabilities & equity	$	1,437,216	$	1,107,689	$	3,168,520	$	(1,153,599	)	$	4,559,826

	December 31, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—		$	374,042		$	—		$	—		$	374,042
Total revenues		—			374,042			—			—			374,042

Costs and expenses:
Lease operating		—			24,904			—			(1	)		24,903
Gathering, processing and transportation		—			72,555			—			(1	)		72,554
Gathering, processing, and transportation - affiliate		—			25,403			—			—			25,403
Exploration		—			8,969			—			—			8,969
Taxes other than income		3,833			11,063			—			—			14,896
Depreciation, depletion and amortization		4,191			184,551			—			—			188,742
Incentive unit compensation expense		35,142			—			—			—			35,142
General and administrative		43,624			2,664			—			—			46,288
Accretion of asset retirement obligations		—			418			—			(1	)		417
(Gain) loss on commodity derivatives		(281,250	)		—			—			1			(281,249	)
(Gain) loss on sale of properties		—			(47	)		—			—			(47	)
Total costs and expenses		(194,460	)		330,480			—			(2	)		136,018
Operating income (loss)		194,460			43,562			—			2			238,024

Other income (expense):
Interest expense, net		(39,308	)		(88	)		—			—			(39,396	)
Equity earnings from subsidiaries		16,434			—			—			(16,434	)		—
Other, net		(100	)		(922	)		—			—			(1,022	)
Total other income (expense)		(22,974	)		(1,010	)		—			(16,434	)		(40,418	)
Income before income taxes		171,486			42,552			—			(16,432	)		197,606
Income tax benefit (expense)		(75,838	)		(24,167	)		—			—			(100,005	)
Net income (loss) from continuing operations		95,648			18,385			—			(16,432	)		97,601
Discontinued Operations
Income (loss) before income taxes		—			—			(397,664	)		(2	)		(397,666	)
Income tax benefit (expense)		—			—			2,175			—			2,175
Net income (loss) from discontinued operations		—			—			(395,489	)		(2	)		(395,491	)
Net income (loss)		95,648			18,385			(395,489	)		(16,434	)		(297,890	)
Net income (loss) attributable to noncontrolling interest		—			—			386			(393,924	)		(393,538	)
Net income (loss) attributable to Memorial Resource Development Corp.	$	95,648		$	18,385		$	(395,875	)	$	377,490		$	95,648

	December 31, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—		$	409,070		$	—		$	—		$	409,070
Other income		5			7			—			—			12
Total revenues		5			409,077			—			—			409,082

Costs and expenses:
Lease operating		—			17,570			—			—			17,570
Gathering, processing and transportation		—			45,956			—			—			45,956
Exploration		—			13,853			—			—			13,853
Taxes other than income		—			12,610			—			—			12,610
Depreciation, depletion and amortization		1,133			127,105			—			—			128,238
Impairment of proved oil and natural gas properties		—			24,576			—			—			24,576
Incentive unit compensation expense		111,866			831,060			1,023			—			943,949
General and administrative		13,232			25,277			16			24			38,549
Accretion of asset retirement obligations		—			533			—			—			533
(Gain) loss on commodity derivatives		(277,129	)		19,395			—			—			(257,734	)
(Gain) loss on sale of properties		—			3,167			(110	)		—			3,057
Other, net		—			—			—			(1	)		(1	)
Total costs and expenses		(150,898	)		1,121,102			929			23			971,156
Operating income (loss)		150,903			(712,025	)		(929	)		(23	)		(562,074	)

Other income (expense):
Interest expense, net		(19,532	)		(30,751	)		—			—			(50,283	)
Loss on extinguishment of debt		(23,562	)		(13,686	)		—			—			(37,248	)
Equity earnings from subsidiaries		(809,017	)		—			—			809,017			—
Other, net		—			319			—			1			320
Total other income (expense)		(852,111	)		(44,118	)		—			809,018			(87,211	)
Income before income taxes		(701,208	)		(756,143	)		(929	)		808,995			(649,285	)
Income tax benefit (expense)		(83,373	)		(19,028	)		—			9			(102,392	)
Net income (loss)		(784,581	)		(775,171	)		(929	)		809,004			(751,677	)
Discontinued Operations
Income (loss) before income taxes		—			—			114,171			22			114,193
Income tax benefit (expense)		—			—			1,430			(9	)		1,421
Net income (loss) from discontinued operations		—			—			115,601			13			115,614
Net income (loss)		(784,581	)		(775,171	)		114,672			809,017			(636,063	)
Net income (loss) attributable to noncontrolling interest		—			—			32			126,756			126,788
Net income (loss) attributable to Memorial Resource Development Corp.	$	(784,581	)	$	(775,171	)	$	114,640		$	682,261		$	(762,851	)

	December 31, 2013
	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Combined & Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—	$	202,423		$	17,129		$	—		$	219,552
Total revenues		—		202,423			17,129			—			219,552

Costs and expenses:
Lease operating		—		14,710			2,605			(108	)		17,207
Gathering, processing and transportation		—		17,666			—			—			17,666
Exploration		—		1,034			—			—			1,034
Taxes other than income		—		7,869			830			—			8,699
Depreciation, depletion and amortization		—		61,990			8,913			—			70,903
Impairment of proved oil and natural gas properties		—		128			2,400			—			2,528
Incentive unit compensation expense		—		14,353			20,644			—			34,997
General and administrative		—		31,674			3,616			124			35,414
Accretion of asset retirement obligations		—		516			77			—			593
(Gain) loss on commodity derivatives		—		(3,179	)		18			—			(3,161	)
(Gain) loss on sale of properties		—		6,776			(89,549	)		—			(82,773	)
Other, net		—		—			2			—			2
Total costs and expenses		—		153,537			(50,444	)		16			103,109
Operating income (loss)		—		48,886			67,573			(16	)		116,443

Other income (expense):
Interest expense, net		—		(24,895	)		(53	)		—			(24,948	)
Equity earnings from subsidiaries		—		71,222			—			(71,222	)		—
Other, net		—		141			2			—			143
Total other income (expense)		—		46,468			(51	)		(71,222	)		(24,805	)
Income before income taxes		—		95,354			67,522			(71,238	)		91,638
Income tax benefit (expense)		—		(164	)		(1,147	)		—			(1,311	)
Net income (loss)		—		95,190			66,375			(71,238	)		90,327
Discontinued Operations
Income (loss) before income taxes		—		—			61,297			16			61,313
Income tax benefit (expense)		—		—			(308	)		—			(308	)
Net income (loss) from discontinued operations		—		—			60,989			16			61,005
Net income (loss)		—		95,190			127,364			(71,222	)		151,332
Net income (loss) attributable to noncontrolling interest		—		—			267			49,563			49,830
Net income (loss) attributable to Memorial Resource Development Corp.	$	—	$	95,190		$	127,097		$	(120,785	)	$	101,502

	December 31, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by continuing operations	$	45,528		$	373,155		$	—		$	(5,941	)	$	412,742
Net cash provided (used in) by discontinued operations		—			(1,127	)		216,750			5,546			221,169
Net cash provided by (used in) operating activities		45,528			372,028			216,750			(395	)		633,911

Cash flows from investing activities:
Acquisitions of oil and natural gas properties		—			(291,536	)		—			—			(291,536	)
Additions to oil and gas properties		—			(594,901	)		—			—			(594,901	)
Additions to other property and equipment		(3,401	)		(452	)		—			—			(3,853	)
Additions to restricted investments		—			—			—			—			—
Other financial hybrid instruments		(46,106	)		—			—			—			(46,106	)
Investments in subsidiaries		(499,336	)		—			—			499,336			—
Distributions from subsidiaries		78,648			—			—			(78,648	)		—
Proceeds from the sale of oil and gas properties		—			13,612			—			—			13,612
Net cash used in continuing operations		(470,195	)		(873,277	)		—			420,688			(922,784	)
Net cash used in discontinued operations		—			63			(337,568	)		—			(337,505	)
Net cash used in investing activities		(470,195	)		(873,214	)		(337,568	)		420,688			(1,260,289	)

Cash flows from financing activities:
Advances on revolving credit facility		798,000			—			—			—			798,000
Payments on revolving credit facility		(558,000	)		—			—			—			(558,000	)
Deferred finance costs		(1,498	)		—			—			—			(1,498	)
Proceeds from MRD equity offering		242,880			—			—			—			242,880
Costs incurred in conjunction with MRD equity offering		(4,773	)		—			—			—			(4,773	)
Capital contributions		—			497,424			—			(497,424	)		—
Repurchases of equity		(51,197	)		—			—			—			(51,197	)
Net cash used in continuing operations		425,412			497,424			—			(497,424	)		425,412
Net cash used in discontinued operations		—			—			120,447			76,736			197,183
Net cash provided by financing activities		425,412			497,424			120,447			(420,688	)		622,595
Net change in cash and cash equivalents		745			(3,762	)		(371	)		(395	)		(3,783	)
Add: cash balance included in assets of discontinued operations at beginning of period		—			2,639			970			(1,015	)		2,594
Less: cash balance included in assets of discontinued operations at end of period		—			—			599			1,576			2,175
Cash and cash equivalents, beginning of period		2,241			1,123			—			—			3,364
Cash and cash equivalents, end of period	$	2,986		$	—		$	—		$	(2,986	)	$	—

	December 31, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Combined & Consolidated
	(In thousands)
Net cash provided by (used in) continuing operations	$	(72,612	)	$	299,206		$	(2,879	)	$	1,975		$	225,690
Net cash provided by (used in) discontinued operations		—			(1,716	)		254,272			(1,975	)		250,581
Net cash provided by (used in) operating activities		(72,612	)		297,490			251,393			—			476,271

Cash flows from investing activities:
Acquisitions of oil and natural gas properties		—			(93,909	)		—			—			(93,909	)
Additions to oil and gas properties		—			(376,123	)		—			1			(376,122	)
Additions to other property and equipment		(15,980	)		(851	)		—			—			(16,831	)
Investments in subsidiaries		(696,489	)		—			—			696,489			—
Distributions from subsidiaries		15,140			74,424			—			(89,564	)		—
Change in restricted cash		—			49,946			—			—			49,946
Deposits for property acquisitions		—			(215	)		—			—			(215	)
Proceeds from the sale of oil and gas properties		—			—			6,700			—			6,700
Other		—			—			(300	)		(1	)		(301	)
Net cash used in continuing operations		(697,329	)		(346,728	)		6,400			606,925			(430,732	)
Net cash used in discontinued operations		—			(138	)		(1,386,109	)		—			(1,386,247	)
Net cash used in investing activities		(697,329	)		(346,866	)		(1,379,709	)		606,925			(1,816,979	)

Cash flows from financing activities:
Advances on revolving credit facility		1,174,000			126,800			—			—			1,300,800
Payments on revolving credit facility		(991,000	)		(329,900	)		—			—			(1,320,900	)
Termination of second lien credit facility		—			(328,282	)		—			—			(328,282	)
Proceeds from the issuances of senior notes		600,000			—			—			—			600,000
Redemption of senior notes		(351,808	)		—			—			—			(351,808	)
Deferred finance costs		(18,779	)		(61	)		—			—			(18,840	)
Proceeds from MRD initial public offering		408,500			—			—			—			408,500
Costs incurred in conjunction with initial public offering		(28,373	)		—			—			—			(28,373	)
MRD equity repurchases		(161	)		—			—			—			(161	)
Capital contributions		—			686,623			—			(686,623	)		—
Contributions from NGP affiliates related to sale of properties		—			—			1,165			—			1,165
Purchase of additional interests in subsidiaries		(3,292	)		—			—			—			(3,292	)
Distribution to equity owners		—			(15,000	)		(2,315	)		17,315			—
Distribution to NGP affiliates related to purchase of assets		—			(63,389	)		(3,304	)		—			(66,693	)
Distribution to noncontrolling interests		—			—			—			(376	)		(376	)
Distributions to MRD Holdco		(17,207	)		(39,520	)		(3,076	)		—			(59,803	)
Distribution to NGP affiliates related to sale of assets, net of cash received		—			(32,770	)		—			—			(32,770	)
Other		302			18			—			—			320
Net cash used in continuing operations		772,182			4,519			(7,530	)		(669,684	)		99,487
Net cash used in discontinued operations		—			—			1,107,714			61,744			1,169,458
Net cash provided by financing activities		772,182			4,519			1,100,184			(607,940	)		1,268,945
Net change in cash and cash equivalents		2,241			(44,857	)		(28,132	)		(1,015	)		(71,763	)
Add: cash balance included in assets of discontinued operations at beginning of period		—			4,493			21,698			—			26,191
Less: cash balance included in assets of discontinued operations at end of period		—			2,639			970			(1,015	)		2,594
Cash and cash equivalents, beginning of period		—			44,126			7,404			—			51,530
Cash and cash equivalents, end of period	$	2,241		$	1,123		$	—		$	—		$	3,364

	December 31, 2013
	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Combined & Consolidated
	(In thousands)
Net cash provided by (used in) continuing operations	$	—	$	92,997		$	(17,702	)	$	13,177		$	88,472
Net cash provided by (used in) discontinued operations		—		867			201,661			(13,177	)		189,351
Net cash provided by (used in) operating activities		—		93,864			183,959			—			277,823

Cash flows from investing activities:
Acquisitions of oil and natural gas properties		—		(67,098	)		—			—			(67,098	)
Additions to oil and gas properties		—		(164,850	)		(20,344	)		—			(185,194	)
Additions to other property and equipment		—		(2,307	)		—			—			(2,307	)
Investment in subsidiaries		—		(93,433	)		—			93,433			—
Distribution from subsidiaries		—		273,694			—			(273,694	)		—
Change in restricted cash		—		(49,347	)		—			—			(49,347	)
Proceeds from the sale of oil and gas properties		—		33,152			118,035						151,187
Net cash used in continuing operations		—		(70,189	)		97,691			(180,261	)		(152,759	)
Net cash used in discontinued operations		—		(125	)		(214,559	)		—			(214,684	)
Net cash used in investing activities		—		(70,314	)		(116,868	)		(180,261	)		(367,443	)

Cash flows from financing activities:
Advances on revolving credit facilities		—		174,400			—			—			174,400
Payments on revolving credit facilities		—		(200,500	)		—			—			(200,500	)
Proceeds from the issuances of senior notes		—		343,000			—			—			343,000
Borrowings under second lien credit facility		—		325,000			—			—			325,000
Deferred financing costs		—		(20,250	)		—			(1	)		(20,251	)
Proceeds from changes in ownership interests in MEMP		—		135,012			—			—			135,012
Purchase of additional interests in subsidiaries		—		(15,135	)		—			—			(15,135	)
Distributions to the Funds		—		(732,362	)		—			—			(732,362	)
Distribution to equity owners		—		—			(74,787	)		74,787			—
Distributions to noncontrolling interests		—		—			—			(7,446	)		(7,446	)
Distributions made by previous owners		—		(2,590	)		—			—			(2,590	)
Other		—		(129	)		—			200			71
Net cash used in continuing operations		—		6,446			(74,787	)		67,540			(801	)
Net cash used in discontinued operations		—		—			6,030			112,721			118,751
Net cash provided by financing activities		—		6,446			(68,757	)		180,261			117,950
Net change in cash and cash equivalents		—		29,996			(1,666	)		—			28,330
Add: cash balance included in assets of discontinued operations at beginning of period		—		3,751			28,585			—			32,336
Less: cash balance included in assets of discontinued operations at end of period		—		4,493			21,698			—			26,191
Cash and cash equivalents, beginning of period		—		14,872			2,183			—			17,055
Cash and cash equivalents, end of period	$	—	$	44,126		$	7,404		$	—		$	51,530

	2016
Oil Hybrid Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		27,080
Weighted-average fixed price	$	46.51
Initial net investment price		62.16
Total contract swap price	$	108.67

NGL Hybrid Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		83,101
Weighted-average fixed price	$	15.84
Initial net investment price		25.98
Total contract swap price	$	41.82

	December 31, 2015
	Carrying		Estimated
Description	Amount		Fair Value
5.875% senior notes, fixed-rate, due May 1, 2022	$	589,064	$	525,000

		Page No.
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2015 and 2014		F-3
Statements of Consolidated and Combined Operations for the Years Ended December 31, 2015, 2014, and 2013		F-4
Statements of Consolidated and Combined Cash Flows for the Years Ended December 31, 2015, 2014, and 2013		F-5
Statements of Consolidated and Combined Equity for the Years Ended December 31, 2015, 2014, and 2013		F-6
Notes to Consolidated and Combined Financial Statements
	Note 1 – Organization and Basis of Presentation	F-8
	Note 2 – Summary of Significant Accounting Policies	F-10
	Note 3 – Discontinued Operations	F-16
	Note 4 – Acquisitions and Divestitures	F-17
	Note 5 – Fair Value Measurements of Financial Instruments	F-19
	Note 6 – Risk Management and Derivative and Other Financial Instruments	F-20
	Note 7 – Asset Retirement Obligations	F-23
	Note 8 – Long Term Debt	F-24
	Note 9 – Stockholders’ Equity and Noncontrolling Interests	F-27
	Note 10 – Earnings per Share	F-28
	Note 11 – Long-Term Incentive Plans	F-29
	Note 12 – Incentive Units	F-30
	Note 13 – Related Party Transactions	F-31
	Note 14 – Income Taxes	F-36
	Note 15 – Commitments and Contingencies	F-37
	Note 16 – Quarterly Financial Information (Unaudited)	F-39
	Note 17 – Supplemental Oil and Gas Information (Unaudited)	F-39
	Note 18 – Condensed Consolidating Financial Information	F-43

	December 31, 2014 Before Adjustment		Adjustment Effect			December 31, 2014 As Adjusted
			(In thousands)
Prepaid expenses and other current assets		12,999		(1,655	)		11,344
Other long-term assets		14,126		(10,540	)		3,586
Accrued liabilities		101,758		(50,522	)		51,236
Long-term debt		783,000		(12,455	)		770,545
Deferred tax liabilities		64,077		50,522			114,599

	December 31,		December 31,
	2015		2014
Accrued capital expenditures	$	40,197	$	44,308
Accrued interest payable		17,657		124
Other accrued liabilities		11,022		6,804
	$	68,876	$	51,236

		Page
	PART II
Item 6.	Selected Financial Data	2
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	4
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	19

	Years Ending December 31,
	2015			2014			2013
Energy Transfer Equity, L.P. and subsidiaries		56	%		85	%		86	%
Plains Marketing, L.P.		11	%	n/a			n/a

	Louisiana
	Acquisition
Oil and gas properties	$	72,141
Asset retirement obligations		(271	)
Total identifiable net assets	$	71,870

Oil and gas properties	$	68,887
Asset retirement obligations		(1,789	)
Total identifiable net assets	$	67,098

	Fair Value Measurements at December 31, 2015 Using
	Quoted Prices in		Significant Other		Significant
	Active		Observable		Unobservable
	Market		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	319,763	$	—	$	319,763

Liabilities:
Commodity derivatives	$	—	$	480	$	—	$	480

		Asset Derivatives						Liability Derivatives
Type	Balance Sheet Location	2015			2014			2015			2014
		(In thousands)
Commodity contracts	Short-term derivative instruments	$	228,349		$	153,026		$	358		$	21,555
Netting arrangements	Short-term derivative instruments		(358	)		(21,555	)		(358	)		(21,555	)
Net recorded fair value	Short-term derivative instruments	$	227,991		$	131,471		$	—		$	—

Commodity contracts	Long-term derivative instruments	$	91,414		$	127,820		$	122		$	4,253
Netting arrangements	Long-term derivative instruments		(122	)		(4,253	)		(122	)		(4,253	)
Net recorded fair value	Long-term derivative instruments	$	91,292		$	123,567		$	—		$	—

	Statements of	For the Year Ended December 31,
	Operations Location	2015			2014			2013
Commodity derivative contracts	(Gain) loss on commodity derivatives	$	(281,249	)	$	(257,734	)	$	(3,161	)
Interest rate derivatives	Interest expense, net		—			296			309

	December 31,
	2015
$2.0 billion revolving credit facility, variable-rate, due June 2019	$	1,000,000


Credit Facility	For the Year Ended December 31,
	2015			2014			2013
Revolving credit facility		1.92	%		1.99	%	n/a
WildHorse Resources revolver terminated June 2014	n/a				4.04	%		2.30	%
WildHorse Resources second lien terminated June 2014	n/a				6.44	%		7.60	%
Black Diamond terminated November 2013	n/a			n/a				3.97	%

Balance January 1, 2014	—
Shares of common stock issued	192,500,000
Shares of common stock repurchased	(123,797	)
Restricted common shares issued (Note 11)	1,068,422
Restricted common shares forfeited	(9,211	)
Balance December 31, 2014	193,435,414
Shares of common stock issued	13,800,000
Shares of common stock repurchased	(2,764,887	)
Restricted common shares issued (Note 11)	938,558
Restricted common shares repurchased (1)	(60,773	)
Restricted common shares forfeited	(54,569	)
Balance December 31, 2015	205,293,743

	Number of Shares			Weighted-Average Grant Date Fair Value per Share (1)
Restricted common shares outstanding at January 1, 2014		—		$	—
Granted (2)		1,068,422		$	19.00
Forfeited		(9,211	)	$	19.00
Restricted common shares outstanding at December 31, 2014		1,059,211		$	19.00
Granted (3)		938,558		$	18.80
Forfeited		(54,569	)	$	18.83
Vested		(274,355	)	$	19.00
Restricted common shares outstanding at December 31, 2015		1,668,845		$	18.89

	Exchanged Incentive Units			Subsequent Incentive Units
Valuation date	12/31/2015			12/31/2015
Dividend yield		0	%		0	%
Expected volatility		51.30	%		51.30	%
Risk-free rate		0.82	%		0.82	%
Expected life (years)		1.42			1.42

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

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

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

Period	MVC (MMBtu/d)		Firm Fee ($/MMBtu)		Interruptible Fee ($/MMBtu)
June 1, 2015 to September 30, 2015		115,000		0.435		0.470
October 1, 2015 to June 30, 2016		345,000		0.435		0.470
July 1, 2016 to June 30, 2026 (1)		460,000		0.435		0.350
July 1, 2026 to June 1, 2030		345,000		0.435		0.350
June 2, 2030 to October 1, 2030		115,000		0.435		0.350

Period	Demand Fee ($/month)		Usage Fee ($/MMBtu)
June 1, 2015 to June 1, 2030	n/a			0.04
January 1, 2016 to December 31, 2025		360,000	n/a

Period		Usage Fee ($/gallon)
October 1, 2015 to October 1, 2030			0.04

			Payment or Settlement due by Period
	Total		2016		2017		2018		2019		2020		Thereafter
	(In thousands)
Operating leases	$	45,323	$	10,509	$	9,344	$	7,368	$	6,776	$	6,203	$	5,123
Sublease rental income		4,021		1,579		1,197		814		431		—		—