UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10–Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2015

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from       to       .

Commission File Number: 001-36490

MEMORIAL RESOURCE DEVELOPMENT CORP.

(Exact name of registrant as specified in its charter)

 

Registrant’s telephone number, including area code: (713) 588-8300

 

 

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ  No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ  No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b–2 of the Exchange Act. Check one:

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b–2 of the Exchange Act).  Yes ¨  No þ

As of April 30, 2015, the registrant had 190,776,618 shares of common stock, $.01 par value, outstanding

 

 

 

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MemORIAL RESOURCE DEVELOPMENT CORP.

Table of Contents

 

 

 

 

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GLOSSARY OF OIL AND NATURAL GAS TERMS

Analogous Reservoir: Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.

Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcfe: One billion cubic feet of natural gas equivalent.

BOEM: Bureau of Ocean Energy Management.

Btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

COPAS: Council of Petroleum Accountants Societies

Dry Hole or Dry Well: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Economically Producible: The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For this determination, the value of the products that generate revenue are determined at the terminal point of oil and natural gas producing activities.

Exploitation: A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Field: An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Gross Acres or Gross Wells: The total acres or wells, as the case may be, in which we have working interest.

MBbl: One thousand Bbls.

Mcf: One thousand cubic feet of natural gas.

MMBtu: One million British thermal units.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

Net Production: Production that is owned by us less royalties and production due others.

NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX: New York Mercantile Exchange.

Oil: Oil and condensate.

Operator: The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.

Play: A geographic area with hydrocarbon potential.

Possible Reserves: Reserves that are less certain to be recovered than probable reserves.

Probable Reserves: Reserves that are less certain to be recovered than proved reserves but that, together with proved reserves, are as likely as not to be recovered.

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Proved Reserves: Those quantities of oil and natural gas, which, 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. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration, unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price used is the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

PUDs: Proved Undeveloped Reserves.

Proved Undeveloped Reserves: Proved oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reliable Technology: Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserve Life: A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year-end by production volumes. In our calculation of reserve life, production volumes are adjusted, if necessary, to reflect property acquisitions and dispositions.

Reserves: Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Resources: Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

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Standardized Measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or standards established by the United States Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”) (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a corporation, we are subject to federal or state income taxes and thus make provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

Wellbore: The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

Working Interest: An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

WTI: West Texas Intermediate.

 

 

 

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NAMES OF ENTITIES

As used in this Form 10-Q, unless we indicate otherwise:

 

 

 

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CAUTIONARY NOTE REGARDING FORWARD–LOOKING STATEMENTS

This quarterly report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, may include statements about our:

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These types of statements, other than statements of historical fact included in this quarterly report, are forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “forecast,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “outlook,” “continue,” the negative of such terms or other comparable terminology. These statements discuss future expectations, contain projections of results of operations or of financial condition or include other “forward-looking” information. These forward-looking statements involve risks and uncertainties. Important factors that could cause our actual results or financial condition to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

The forward-looking statements contained in this quarterly report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this quarterly report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events or circumstances described in any forward-looking statement will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in the “Part I—Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2014 (our “2014 Form 10-K) and “Part II—Item 1A. Risk Factors” appearing within this quarterly report and elsewhere in this quarterly report. All forward-looking statements speak only as of the date of this quarterly report. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

 

 

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PART I—FINANCIAL INFORMATION

 

 

MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding shares)

 

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements.

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MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS

(In thousands, except per share amounts)

 

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements.

 

 

 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS

 (In thousands)

 

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements.

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MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY

(In thousands)

 

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements.

 

 

 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 1. Background, Organization and Basis of Presentation

Overview

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.

References to: (i) “Memorial Production Partners,” “MEMP” and “the Partnership” refer to Memorial Production Partners LP individually and collectively with its subsidiaries, as the context requires; (ii) “MEMP GP” refer to Memorial Production Partners GP LLC, the general partner of the Partnership, which we own; (iii) “MRD Holdco” refer to MRD Holdco LLC, a holding company controlled by the Funds (defined below) that, together as part of a group, owns a majority of our common stock; (iv) “MRD LLC” refer to Memorial Resource Development LLC, which historically owned our predecessor’s business and was merged into MRD Operating LLC (“MRD Operating”), our 100% owned subsidiary, subsequent to our initial public offering; (v) “WildHorse Resources” refer to WildHorse Resources, LLC, which owned our interest in the Terryville Complex and merged into MRD Operating in February 2015; (vi) “our predecessor” refer collectively to MRD LLC and its former consolidated subsidiaries, consisting of Classic Hydrocarbons Holdings, L.P., Classic Hydrocarbons GP Co., L.L.C., Black Diamond Minerals, LLC, Beta Operating Company, LLC, MEMP GP, BlueStone Natural Resources Holdings, LLC (“BlueStone”), MRD Operating, WildHorse Resources, Tanos Energy LLC and each of their respective subsidiaries, including MEMP and its subsidiaries; (vii) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively control MRD Holdco; and (viii) “NGP” refer to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the Funds.

Previous Owners

References to “the previous owners” for accounting and financial reporting purposes refer to the net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) in February 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of certain acquisitions in 2010, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods.

Our unaudited financial statements reported herein include the financial position and results attributable to NGPCIF NPI.

Basis of Presentation

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

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.

All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. Our results of operations for the three months ended March 31, 2015 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”).

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

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Segment financial information has been retrospectively revised for the acquisition by the MEMP Segment of certain assets from the MRD Segment in East Texas in February 2015 in exchange for approximately $78.0 million in cash and certain properties in North Louisiana (the “Property Swap”) for comparability purposes. Our equity statement reflects a $172.9 million equity transfer from stockholders’ equity to noncontrolling interest related to this transaction. This amount represents $250.8 million of net book value related to the assets transferred to MEMP allocated to its limited partners less $77.9 million of cash allocated to its limited partners. Amounts allocated to MEMP GP eliminate in consolidation.

Use of Estimates

The preparation of the accompanying unaudited condensed 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 compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.

 

Note 2. Summary of Significant Accounting Policies

A discussion of our critical accounting policies and estimates is included in our 2014 Form 10-K.

Accrued liabilities

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

Income Tax

Our predecessor was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes prior to our initial public offering in June 2014; however, certain of its consolidating subsidiaries were subject to federal and certain state income taxes.  We are organized as a taxable C corporation and subject to federal and certain state income taxes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax. The net income (loss) attributable to noncontrolling interest is related to MEMP, which is a pass-through entity for federal income tax purposes.  As discussed in Note 12, the compensation expense associated with the incentive units of MRD Holdco creates a nondeductible permanent difference for income tax purposes. We reported no liability for unrecognized tax benefits as of March 31, 2015 and expect no significant change to the unrecognized tax benefits in the next twelve months. 

Our effective tax rate is negative 67.5% for the three months ended March 31, 2015, which differs from the statutory federal income tax rate of 35% primarily due to the following recurring items:

We had a net noncurrent deferred income tax liability of $95.0 million at December 31, 2014, of which $29.2 million was attributable to certain oil and gas properties in East Texas that MEMP acquired from us in February 2015 as noted above.  A deferred income tax benefit of $1.2 million associated with these oil and gas properties was recorded during February 2015.  As such, a net deferred income tax liability of $28.0 million has been reduced through additional paid capital in our equity statement. 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

New Accounting Pronouncements

Presentation of Debt Issuance Cost. In April 2015, the Financial Accounting Standards Board ("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 does not expect the impact of adopting this guidance to be material to the Company's financial statements and related disclosures.

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

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

 

 

Note 3. Acquisitions and Divestitures

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

2015 Divestitures

Subsequent event. On April 17, 2015, MRD sold certain oil and natural gas properties to a third party in Colorado and Wyoming for approximately $13.5 million (the “Rockies Divestiture”).

2014 Acquisitions

On March 25, 2014, MEMP closed a transaction to acquire certain oil and natural gas producing properties from a third party in the Eagle Ford (the “Eagle Ford Acquisition”). In addition, MEMP acquired a 30% interest in the seller’s Eagle Ford leasehold.

In July 2014, MEMP closed a third-party acquisition that was deemed significant to our consolidated financial statements. The following unaudited pro forma combined results of operations are provided for the three months ended March 31, 2014 as though this third-party acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of our predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. 

 

 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 4. Fair Value Measurements of Financial Instruments

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

The carrying values of accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at March 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.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The fair market values of the derivative financial instruments reflected on the balance sheets as of March 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 gross derivative assets and liabilities that are measured at fair value on a recurring basis at March 31, 2015 and December 31, 2014 for each of the fair value hierarchy levels:

 

See Note 5 for additional information regarding our derivative instruments.

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

 

 

Note 5. Risk Management and Derivative Instruments

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

Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreements are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party.

At March 31, 2015, MEMP had net derivative assets of $601.0 million. After taking into effect netting arrangements, MEMP had counterparty exposure of $328.4 million related to its derivative instruments of which $113.4 million was with a single counterparty. Had all counterparties failed completely to perform according to the terms of their existing contracts, MEMP would have the right to offset $272.6 million against amounts outstanding under its revolving credit facility at March 31, 2015. At March 31, 2015, MRD had net derivative assets of $330.5 million. After taking into effect netting arrangements, MRD had counterparty exposure of $248.7 million related to derivative instruments of which $66.6 million was with a single counterparty. Had all counterparties failed completely to perform according to the terms of their existing contracts, MRD would have the right to offset $81.8 million against amounts outstanding under its revolving credit facility at March 31, 2015. See Note 8 for additional information regarding our revolving credit facilities.

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Commodity Derivatives

We may use a combination of commodity derivatives (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 derivative instruments have a deferred premium. The deferred premium is factored into the fair value measurement and the Company agrees to defer the premium paid or received until the time of settlement. Cash settlements received on settled derivative positions during the three months ended March 31, 2015 is net of deferred premiums of $1.8 million.

In February 2015, MEMP restructured a portion of its commodity derivative portfolio by effectively terminating “in-the-money” crude oil derivatives settling in 2015 through 2017 and entering into NGL derivatives with the same tenor. Cash settlement receipts of approximately $27.1 million from the termination of the crude oil derivatives were applied as premiums for the new NGL derivatives.

We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub and regional indices such as NGPL TXOK, TETCO STX, TGT Z1, and Houston Ship Channel in proximity to our areas of production. We also enter into oil derivative contracts indexed to a variety of locations such as NYMEX-WTI, Inter-Continental Exchange (“ICE”) Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu.

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

At March 31, 2015, the MRD Segment had the following open commodity positions:

 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

At March 31, 2015, the MEMP Segment had the following open commodity positions:

 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below:

Interest Rate Swaps

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 agreements to fixed interest rates. From time to time we enter into offsetting positions to avoid being economically over-hedged. At March 31, 2015, we had the following interest rate swap open positions:

 

Balance Sheet Presentation

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

 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

(Gains) Losses on Derivatives

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 three months ended March 31, 2015 and 2014 (in thousands):

 

 

 

Note 6. Asset Retirement Obligations

Asset retirement obligations primarily relate to our portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the three months ended March 31, 2015 (in thousands):

 

 

 

Note 7. Restricted Investments

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with offshore Southern California oil and gas properties owned by MEMP. The components of the restricted investment balance consisted of the following at the dates indicated:

 

 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

 

Note 8. Long Term Debt

The following table presents our consolidated debt obligations at the dates indicated:

 

Borrowing Base

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

 

Subsequent event. On April 13, 2015, MRD’s revolving credit facility borrowing base was re-affirmed at $725.0 million.

Weighted-Average Interest Rates

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

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Unamortized Deferred Financing Costs

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

 

 

Note 9. Stockholders’ Equity and Noncontrolling Interests

Common Stock

The Company's authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the three months ended March 31, 2015:

See Note 11 for additional information regarding restricted common shares. Restricted shares of common stock are considered issued and outstanding on the grant date of the restricted stock award.

Share Repurchase Program

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

Subsequent event. In April 2015, 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. 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.

Noncontrolling Interests

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

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

During the three months ended March 31, 2015, MEMP repurchased 1,909,583 common units under its repurchase program for an aggregate price of $28.4 million. MEMP has retired all common units repurchased and those common units are no longer issued or outstanding.

 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 10. Earnings per Share

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

 

 

 

Note 11. Long-Term Incentive Plans

MRD

The following table summarizes information regarding restricted common share awards granted under the Memorial Resource Development Corp. 2014 Long-Term Incentive Plan for the periods presented:

 

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

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 $17.7 million at March 31, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 3.13 years.

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

MEMP

The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan 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 unit awards was $16.3 million at March 31, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.99 years. Since the restricted common units are participating securities, distributions received by the restricted common unitholders are generally included in distributions to noncontrolling interests as presented on our unaudited condensed statements of consolidated and combined cash flows.

 

 

Note 12. Incentive Units

MRD Holdco

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 $10.2 million of compensation expense during the three months ended March 31, 2015, offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $95.5 million as of March 31, 2015 will be recognized over the remaining expected service period of 2.17 years.

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

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

 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 13. Related Party Transactions

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

NGP Affiliated Companies

During the three months ended March 31, 2015, MRD paid approximately $0.6 million to Cretic Energy Services, LLC, a NGP affiliated company, for services related to our drilling and completion activities.

NGPCIF NPI Acquisition

WildHorse Resources purchased a net profits interest 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.

Other Acquisitions or Dispositions

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, our predecessor acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from a NGP affiliated company for $3.3 million. Due to common control considerations, this transaction was recognized in the equity statement.

Related Party Agreements

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

Registration Rights Agreement

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.

Voting Agreement

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

Services Agreement

In connection with the closing of our initial public offering, we entered into a services agreement with WildHorse Resources and WildHorse Resource Management Company, LLC (“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 (“WHR II”). NGP and certain former management members of WildHorse Resources own WHR II.

The services agreement was terminated effective March 1, 2015.

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

WildHorse Management Services Agreement

A discussion of the WildHorse and WHR II management services and related agreements is included in our 2014 Form 10-K. These agreements were terminated in connection with our initial public offering.

Gas Processing Agreement

Subsequent event. On April 14, 2015, we, through our wholly-owned subsidiary, MRD Operating, entered into an amended and restated gas processing agreement (“GPA”) with PennTex North Louisiana Operating, LLC (“PennTex Operating”), a wholly-owned subsidiary of PennTex North Louisiana, LLC (“PennTex”). WildHorse Resources, which owned our interest in the Terryville Complex and merged into MRD Operating in February 2015, initially entered into a gas processing agreement with PennTex in March 2014, prior to our initial public offering. PennTex is a joint venture among certain affiliates of NGP in which MRD Midstream LLC, a wholly-owned subsidiary of MRD Holdco, owns a minority interest. Once PennTex Operating’s first processing plant becomes operational, it will process natural gas produced from wells located on certain leases owned by us in the state of Louisiana. The GPA has a 15-year primary term, subject to one-year extensions at either party’s election. We will pay PennTex Operating a monthly volume processing fee, subject to annual inflation escalators, based on volumes of natural gas processed by PennTex Operating. Once the first plant is declared operational, we will be obligated to pay a minimum processing fee equal to approximately $18.3 million on an annual basis, subject to certain adjustments and conditions until the second processing plant is declared operational. Once the second plant is declared operational, we will be obligated to pay a minimum volume processing fee equal to approximately $55.0 million on an annual basis, subject to certain adjustments and conditions.

In addition, on April 14, 2015, we entered into (i) an amended and restated area of mutual interest and midstream exclusivity agreement (“AMI”) with PennTex NLA Holdings, LLC, which owns a majority interest in PennTex, MRD WHR LA Midstream LLC, an affiliate of MRD Holdco, and PennTex, (ii) a gas transportation agreement (“GTA”) with PennTex Operating, (iii) a gas gathering agreement (“GGA”) with PennTex Operating, and (iv) a transportation services agreement (“TSA” and, together with the GPA, AMI, GTA, and GGA, the “Midstream Agreements”) with PennTex Operating to provide gathering, residue gas and natural gas liquids transportation services to us in the state of Louisiana. The Midstream Agreements have a 15-year primary term, subject to one-year extensions at either party’s elections.

Under the GGA, once the first processing plant is declared operational, we will pay PennTex Operating a commodity usage charge equal to at least the minimum volume commitment (115,000 MMBtu per day) times $0.02 per MMBtu until PennTex Operating’s second processing plant is declared operational. Once the second processing plant is declared operational, we will pay PennTex Operating a commodity usage charge equal to at least an increased minimum volume commitment (345,000 MMBtu per day) times $0.02 MMBtu through November 30, 2019. The minimum volume commitment will increase to 460,000 MMBtu on July 1, 2016 and may further increase subject to the terms of the GGA. Prior to December 1, 2019, PennTex Operating is also entitled to a payback demand fee from us equal to the monthly demand quantity (460,000 MMBtu per day) times a $0.03 MMBtu through November 30, 2019. Beginning on December 1, 2019, PennTex Operating is not entitled to a monthly demand charge, the commodity usage charge escalates to $0.05 per MMBtu, and PennTex Operating is entitled to receive a commodity usage charge from us equal to the minimum volume commitment (460,000 MMBtu per day through June 30, 2026, and 345,000 MMBtu per day thereafter) times $0.05 MMBtu.

Similarly, under each of the GTA and TSA, which commence concurrently with the operational dates of the two processing plants, PennTex Operating will be entitled to a commodity usage charge of $0.04 per MMBtu for all volumes of residue gas and natural gas liquids produced on our behalf.

Under the AMI, we granted PennTex Operating the exclusive right to build all of our midstream infrastructure in northern Louisiana and to provide midstream services to support our current and future production on our operated acreage within such area (other than production subject to existing third-party commitments).

Classic Pipeline Gas Gathering Agreement & Water Disposal Agreement

In November 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. In May 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed, and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement has a term until December 31, 2023, subject to one-year extensions at either party’s election.

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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

In February 2015, in connection with and as part of the Property Swap, Classic sold all of the equity interests owned by it in Classic Operating to Memorial Production Operating LLC, a wholly-owned subsidiary of MEMP, and Classic and Classic GP were merged into MRD Operating in March 2015.

 

 

Note 14. Business Segment Data

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

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

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

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

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

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

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

 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Calculation of Reportable Segments’ Adjusted EBITDA

 

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

 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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

 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

 

 

Note 15. Commitments and Contingencies

Litigation & Environmental

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

At March 31, 2015 and December 31, 2014, we had $1.3 million and $2.1 million of environmental reserves recorded on our balance sheets, respectively.

Gas Processing Agreement

See Note 13 for additional information.

Supplemental Bond for Decommissioning Liabilities Trust Agreement

In connection with its 2009 acquisition of the Beta properties, Rise Energy Operating, LLC (“REO”), a wholly-owned subsidiary of MEMP, assumed an obligation with the BOEM for the decommissioning of the offshore production facilities. The trust account is held by REO for the benefit of all working interest owners. The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of March 31, 2015 (in thousands):

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands):

As of March 31, 2015, the maximum remaining obligation net to REO’s interest was approximately $7.4 million.

Processing Plant Expansions by Third Party Gatherer

A discussion of processing plant expansions by a third party gatherer is included in our 2014 Form 10-K.

Related Party Agreements

See Note 13 for additional information.

 

 

Note 16. Subsequent Events

MRD Common Stock Repurchase Approval

For additional information, see Note 9.

MRD Borrowing Base Reaffirmed

For additional information, see Note 8.

MRD Sale of Oil and Natural Gas Properties in Colorado and Wyoming

For additional information, see Note 3.

MRD and PennTex Midstream Agreements

For additional information, see Note 13.

 

 

 

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Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the unaudited condensed financial statements and accompanying notes in “Item 1. Financial Statements” contained herein and our 2014 Form 10-K filed with the SEC on March 18, 2015 and any supplements thereto. 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. See “Cautionary Note Regarding Forward-Looking Statements” in the front of this report.

Overview

We are an independent natural gas and oil company focused on the acquisition, exploration and development of natural gas and oil properties with a majority of our activity in the Terryville Complex of North Louisiana, where we are targeting overpressured, liquids-rich natural gas opportunities in multiple zones in the Cotton Valley formation. We are focused on creating shareholder value primarily through the development of our sizeable horizontal inventory.

We have two reportable segments, both of which are engaged in the acquisition, exploration and development of oil and natural gas properties:

Because we control MEMP through our ownership of its general partner, its business and operations are consolidated with ours for financial reporting purposes, even though we do not own any of its common units. As a result, our financial statements and notes thereto included under “Item 1. Financial Statements” consolidate MEMP’s business and assets with ours; however, the MEMP Segment’s debt is nonrecourse to the Company. Except where expressly noted to the contrary, the following discussion of our business, operations and assets and the use of the terms “we”, “our” and “us” excludes MEMP’s business, operations and assets.

As discussed under Note 2 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements,” the FASB issued an accounting standards update in February 2015 to improve consolidation guidance for certain types of legal entities. The guidance, among other things, modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities and eliminates the presumption that a general partner should consolidate a limited partnership. We will either: (i) continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements or (ii) no longer consolidate MEMP under the revised VIE consolidation requirements and provide disclosures that apply to variable interest holders that do not consolidate a VIE. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosures.

Recent Developments

Property Swap

In February 2015, we and MEMP completed a transaction (the “Property Swap”) in which we exchanged certain of our oil and gas properties in East Texas and non-core Louisiana for MEMP’s North Louisiana oil and gas properties and approximately $78.0 million in cash, subject to customary adjustments. Terms of the transaction were approved by our board of directors and by its conflicts committee, which is comprised entirely of independent directors. The transaction had an effective date of January 1, 2015.

Amendment to MRD Revolving Credit Facility and Borrowing Base Reaffirmation

In April 2015, we entered into a fourth amendment to our revolving credit facility to, among other things, add new lenders and permit the repurchase of up to $50.0 million of our common stock. In connection therewith, the lenders under our revolving credit facility reaffirmed the borrowing base under our revolving credit facility at $725.0 million, to remain at such level until the next scheduled redetermination, the next interim redetermination or other adjustment to the borrowing base, whichever occurs first.

MEMP Borrowing Base Redetermination

In connection with the semi-annual borrowing base redetermination by lenders under MEMP’s revolving credit facility, the borrowing base under its revolving credit facility decreased from $1.44 billion to $1.3 billion. This reduction in the borrowing base was primarily the result of the deterioration of commodity prices in the oil and natural gas industry. The new borrowing base became effective on March 24, 2015.

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Business Segments

Our reportable business segments are organized in a manner that reflects how management manages those business activities. We evaluate segment performance based on Adjusted EBITDA. For additional information regarding our reportable business segments and Adjusted EBITDA, see Note 14 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

Segment financial information has been retrospectively revised for the acquisition by the MEMP Segment of certain assets from the MRD Segment in East Texas in February 2015 in exchange for approximately $78.0 million in cash and certain properties in North Louisiana for comparability purposes.

The MRD Segment is focused on the acquisition, exploration, and development of natural gas and oil properties primarily in the Cotton Valley formation in North Louisiana. These properties consist primarily of assets with extensive production histories, high drilling success rates, and significant horizontal redevelopment potential. The MRD Segment is focused on maintaining and growing its production and cash flow primarily through the development of its sizeable inventory. The MRD Segment, prior to our initial public offering, included BlueStone, MRD Royalty, MRD Midstream, Golden Energy, Classic Pipeline, the MEMP subordinated units and cash held in a debt service reserve account that had been established when the 10.00%/10.75% Senior PIK toggle notes due 2018 (the “PIK notes”) were issued by MRD LLC in December 2013.

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

Sources of Revenues

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

Principal Components of Cost Structure

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Critical Accounting Policies and Estimates

Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair value of incentive unit compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. These estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis.

When used in the preparation of our consolidated financial statements, such estimates are based on our current knowledge and understanding of the underlying facts and circumstances and may be revised as a result of actions we take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.

 

 

Results of Operations

MRD Segment

The MRD Segment’s consolidated and combined results of operations for the three months ended March 31, 2015 and 2014 presented below have been derived from our consolidated and combined financial statements. The comparability of the results of operations among the periods presented is impacted by the distribution by MRD LLC of the following to MRD Holdco prior to our initial public offering: (i) BlueStone, which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owns certain immaterial leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owns an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline and (ii) 5,360,912 subordinated units of MEMP (which converted to common units on February 13, 2015).

Segment financial information has been retrospectively revised for material common control transactions between the MEMP Segment and the MRD Segment for comparability purposes, which includes the acquisition by the MEMP Segment of certain assets from the MRD Segment in East Texas in February 2015 in exchange for approximately $78.0 million in cash and certain properties in North Louisiana.

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Three Months Ended March 31, 2015 Compared to the Three Months Ended March 31, 2014

The MRD Segment recorded net income of $50.4 million during the three months ended March 31, 2015 compared to net income of $6.4 million during the three months ended March 31, 2014.

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Given the volatility of commodity prices, it is not possible to predict future reported 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 $182.3 million during 2015. Average outstanding borrowings under the predecessor’s revolving credit facilities were $250.9 million during 2014. For 2015, we had an average of $600.0 million aggregate principal amount of the MRD Senior Notes issued and outstanding. For 2014, we had an average of $360.0 million aggregate principal amount of the PIK notes issued and outstanding and an average of $325.0 million aggregate principal outstanding for the WildHorse Resources’ second lien term facility.

MEMP Segment

The MEMP Segment’s consolidated and combined results of operations for the three months ended March 31, 2015 and 2014 presented below have been derived from our consolidated and combined financial statements. The comparability of the results of operations among the periods presented is impacted by the following transactions:

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Three Months Ended March 31, 2015 Compared to the Three Months Ended March 31, 2014

Net loss of $162.7 million was generated for the three months ended March 31, 2015, primarily due to impairment expenses, compared to a net loss of $32.9 million generated for the three months ended March 31, 2014.

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Average outstanding borrowings under MEMP’s revolving credit facility were $513.8 million during 2015 compared to $148.8 million during 2014. For 2015, MEMP had an average of $1.2 billion aggregate principal amount of MEMP’s senior notes issued and outstanding. For 2014, MEMP had an average of $700 million aggregate principal amount of MEMP’s senior notes issued and outstanding.

Consolidated

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

 

 

Liquidity and Capital Resources

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

MRD Segment

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

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.

We believe our cash flows provided by operating activities and availability under our revolving credit facility will provide us with the financial flexibility and wherewithal to meet our cash requirements, including normal operating needs, and pursue our currently planned 2015 development drilling activities. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and 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.

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As of March 31, 2015, our liquidity of $584.4 million consisted of $3.4 million of cash and cash equivalents and $581.0 million of available borrowings under our revolving credit facility. As of March 31, 2015, we had a working capital balance of $45.3 million, which included $142.1 million related to the fair value of derivative instruments that expire in the next 12 months.

Capital Budget

For the three months ended March 31, 2015, MRD Segment’s total capital expenditures were $93.4 million related primarily to the development of the Terryville Complex.

Debt Agreements—MRD Segment

Revolving Credit Facility

In June 2014, we, as borrower, and certain of our subsidiaries, as guarantors, entered into a revolving credit facility, which is a five-year, $2.0 billion revolving credit facility with a borrowing base of $725.0 million as of March 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 April 2015, the borrowing base under our revolving credit facility was re-affirmed at $725.0 million. 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.

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 March 31, 2015.

See Note 8 under “Item 1. Financial Statements” for additional information regarding our revolving credit facility.

MRD Senior Notes

As of March 31, 2015, MRD had $600.0 million aggregate principal amount of 5.875% senior unsecured notes due 2022 (the “MRD Senior Notes”) outstanding. 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 1. Financial Statements” for additional information regarding the MRD Senior Notes.

Debt Agreements—MEMP Segment

Revolving Credit Facility

Memorial Production Operating LLC (“OLLC”), a wholly-owned subsidiary of MEMP, is party to a $2.0 billion revolving credit facility, with a current borrowing base of $1.3 billion that matures in March 2018 and is guaranteed by MEMP and all of its current and future subsidiaries (other than certain immaterial subsidiaries). See Note 8 under “Item 1. Financial Statements” for additional information regarding MEMP’s revolving credit facility.

Senior Notes

As of March 31, 2015, MEMP had $700.0 million aggregate principal of amount of 7.625% senior notes due 2021 (“2021 Senior Notes”) outstanding. The 2021 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2021 Senior Notes, and certain immaterial subsidiaries). The 2021 Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes were issued under and are governed by an indenture dated as of April 17, 2013.

As of March 31, 2015, MEMP had approximately $497.0 million aggregate principal amount of 6.875% senior notes due 2022 (“2022 Senior Notes”) outstanding. The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2022 Senior Notes, and certain immaterial subsidiaries). The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year. The 2022 Senior Notes were issued under and are governed by an indenture dated as of July 17, 2014.

See Note 8 under “Item 1. Financial Statements” for additional information regarding the 2021 Senior Notes and 2022 Senior Notes.

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Commodity Derivative Contracts

Our hedging policy is designed to reduce the impact to our cash flows from commodity price volatility.

For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of March 31, 2015, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk.”

Interest Rate Derivative Contracts

Periodically, we may 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. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time-to-time we may enter into offsetting positions to avoid being economically over-hedged.

See “Item 3. Quantitative and Qualitative Disclosure About Market Risk” for a summary of our derivative contracts as of March 31, 2015.

Counterparty Exposure

Our hedging policy permits us to enter into derivative contracts with major financial institutions or major energy entities. Our derivative contracts are currently with major financial institutions, certain of which are also lenders under our revolving credit facility. We have rights of offset against the borrowings under our revolving credit facility. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk” for additional information.

Cash Flows from Operating, Investing and Financing Activities

The following tables summarize segment cash flows from operating, investing and financing activities for the periods indicated. For information regarding the individual components of our cash flow amounts, see the Unaudited Condensed Statements of Consolidated and Combined Cash Flows included under Item 1 of this quarterly report.

MRD Segment

Three Months Ended March 31, 2015 Compared to the Three Months Ended March 31, 2014

Operating Activities. Net cash flows provided by operating activities were $98.8 million during 2015 compared to $49.1 million during 2014. Production increased 11.6 Bcfe (approximately 87%) and average realized sales price decreased $3.11 per Mcfe as previously discussed under “Results of Operations—MRD Segment.” Cash paid for interest during 2015 was $17.9 million compared to $7.4 million during 2014 and cash settlements on commodity derivatives were $37.9 million higher in 2015.

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Investing Activities. Total cash used in investing activities was $88.5 million during 2015 compared to $72.6 million for the same period in 2014. Cash used for additions to oil and gas properties was $86.6 million during 2015 compared to $75.2 million for the same period in 2014, which consisted primarily of drilling and completion activities in North Louisiana. Additions to other property and equipment were $1.9 million which consisted primarily of computer hardware, software, and other leased office space build out during 2015. Distributions of $0.1 million and $3.0 million were received from MEMP related to partnership interests owned by the MRD Segment during 2015 and 2014, respectively.  MRD LLC owned MEMP subordinated units during 2014.  These MEMP partnership interests were distributed to MRD Holdco in connection with Company’s initial public offering in June 2014.

Financing Activities.  Net repayments under our revolving credit facility were $39.0 million during 2015 compared to net advances of $68.0 million during 2014 under WildHorse Resources revolving credit facility. WildHorse Resources primarily utilized its revolving credit facility during 2014 to repurchase net profits interests from an affiliate of NGP.

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.

MEMP paid $78.0 million to MRD during 2015 in connection with the Property Swap acquisition. MRD made deemed distributions of $1.9 million and $1.0 million to MEMP related to the properties MEMP acquired in the Property Swap transaction during 2015 and 2014, respectively.

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. At December 31, 2014, there was $2.2 million accrued for 123,797 shares that were repurchased and retired in 2014. 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 $0.9 million were incurred during 2014.

MEMP Segment

Three Months Ended March 31, 2015 Compared to the Three Months Ended March 31, 2014

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities increased by $17.2 million although net income decreased by $129.8 million. Production increased 5.9 Bcfe (approximately 35%while average realized sales price decreased 2.85 per Mcfe. The decrease is due to the 2015 impairment as further discussed above under “Results of Operations—MEMP Segment.” Net cash provided by operating activities included a period-to-period increase in cash settlements received on expired commodity derivatives of $67.2 million and $0.5 million period-to-period decrease in cash flow attributable to the timing of cash receipts and disbursements related to operating activities.

Investing Activities. Net cash used in investing activities during 2015 was $79.1 million, of which $3.3 million was used to acquire oil and natural gas properties from a third parties and $74.4 million was used for additions to oil and gas properties. Cash used in investing activities during 2014 was $232.8 million, of which $173.0 million was used to acquire oil and natural gas properties from a third parties and $59.0 million was used for additions to oil and gas properties. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties.

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Financing Activities. Distributions to partners during 2015 were $46.3 million compared to $33.8 million during 2014, of which the MRD Segment received $0.1 million during 2015 compared to $3.0 million during 2014. The MRD Segment received $78.0 million from MEMP in connection with the Property Swap acquisition. MEMP received a contribution of $1.9 million and $1.0 million from the MRD Segment related to the properties MEMP acquired in the Property Swap transaction during 2015 and 2014, respectively.

MEMP had net borrowings of $161.0 million under its revolving credit facility during 2015 that were primarily used to fund the Property Swap acquisition and to fund MEMP’s drilling program. MEMP had borrowings of $196.0 million under its revolving credit facility during 2014 that were used primarily to fund its March 2014 Eagle Ford acquisition and drilling program.

MEMP repurchased $28.4 million in common units during 2015, which represents a repurchase and retirement of 1,909,583 common units under the MEMP Repurchase Program. MEMP repurchased a principal amount of approximately $3.0 million of the 2022 Senior Notes at a price of 83.000% of the face value of the 2022 Senior Notes in January 2015, of which $2.9 million was classified as a financing outflow representing repayment of the original proceeds and $0.3 million classified as an operating inflow.

Contractual Obligations

During the three months ended March 31, 2015, there were no significant changes in our consolidated contractual obligations from those reported in our 2014 Form 10-K filed with the SEC on March 18, 2015.

Off–Balance Sheet Arrangements

As of March 31, 2015, we had no off–balance sheet arrangements.

Recently Issued Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see Note 2 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

 

 

In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. We may enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes. We do not designate these or plan to designate future derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings. We believe that our exposures to market risk have not changed materially since those reported under “Quantitative and Qualitative Disclosures About Market Risk,” included in our 2014 Form 10-K filed with the SEC on March 18, 2015.

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our natural gas, oil and NGL production. To reduce the impact of fluctuations in commodity 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 production through various transactions that fix the future prices received.

For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of March 31, 2015, see Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

Interest Rate Risk

Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. See Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report for interest rate swap arrangements that were outstanding at March 31, 2015.

At March 31, 2015, we had $144.0 million of Eurodollar borrowings outstanding under our revolving credit facility, with an interest rate of LIBOR plus 1.50%, or 1.66%. Assuming no change in the amount of debt outstanding, the impact on interest expense of a 10% increase or decrease in the in the variable component of the stated interest rates would be less than $0.1 million per year.

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The fair value of MRD Senior Notes, MEMP’s 2022 Senior Notes and MEMP’s 2021 Senior Notes is sensitive to changes in interest rates. We estimate the fair value of MRD Senior Notes, MEMP’s 2022 Senior Notes and MEMP’s 2021 Senior Notes using quoted market prices. The carrying value (net of any discount or premium) is compared to the estimated fair value in the table below (in thousands):

Counterparty and Customer Credit Risk

We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. In addition, our derivative contracts may expose us to credit risk in the event of nonperformance by counterparties. See Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information regarding credit risk associated with our derivative instruments.

 

 

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2015. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2015 at the reasonable assurance level.

Change in Internal Controls Over Financial Reporting

No changes in our internal control over financial reporting occurred during the quarter ended March 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 are filed as Exhibits 31.1 and 31.2, respectively, to this quarterly report.

 

 

 

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PART II—OTHER INFORMATION

 

 

For information regarding legal proceedings, see Part I, “Item 1. Financial Statements”, Note 15, “Commitments and Contingencies – Litigation & Environmental,” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included in this quarterly report, which is incorporated herein by reference.

 

 

In addition to the risk factor described below, security holders and potential investors in our securities should carefully consider the risk factors disclosed in our 2014 Form 10-K filed with the SEC on March 18, 2015.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays, and adversely affect our production.

Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. We routinely apply hydraulic fracturing techniques in our drilling and completion programs.

While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. For example, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities under the Safe Drinking Water Act, or the SDWA, involving the use of diesel fuels and published permitting guidance in February 2014 addressing the use of diesel in fracturing operations. Although the EPA is not the permitting authority for the SDWA’s Underground Injection Control Class II programs in Louisiana, Texas, Wyoming, New Mexico, or Colorado, where we or MEMP maintain operational acreage, the EPA is encouraging state programs to review and consider use of such draft guidance. Also, the EPA is updating chloride water quality criteria for the protection of aquatic life under the Clean Water Act, which criteria are used by states for establishing acceptable discharge limits. The EPA is expected to release draft criteria in early 2016. On April 7, 2015, the EPA published in the Federal Register a proposed rule requiring federal pre-treatment standards for wastewater generated during the hydraulic fracturing process. Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting “flowback,” as well as “produced water.” If adopted, the new pretreatment rules will require shale gas operations to pretreat wastewater before transferring it to treatment facilities.  The proposed rule is undergoing a public comment period, which ends on June 8, 2015. Moreover, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking public comment on its intent to develop and issue regulations under the Toxic Substances Control Act regarding the disclosure of information related to the chemicals used in hydraulic fracturing. The public comment period ended on September 18, 2014.

In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants programs. The rules include NSPS standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rules seek to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of these requests for reconsideration. For example, in September 2013 and December 2014, the EPA published updates to the 2012 performance standards. Specifically, on September 23, 2014, the EPA finalized the portion of the rule addressing VOC emissions from storage tanks, including a phase-in period and an alternative emissions limit for older tanks. On December 19, 2014, the EPA issued clarification on the manner in which gases and liquids should be handled during well completion operations, as well as changes to the requirements for storage vessels. In addition, on January 14, 2015, the EPA announced a series of steps it plans to take to address methane and smog-forming VOC emissions from the oil and gas industry. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

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In addition, on March 26, 2015, the federal Bureau of Land Management published a final rule governing hydraulic fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, development of appropriate plans for managing flowback water that returns to the surface, increased standards for interim storage of recovered waste fluids, and submission to the Bureau of Land Management of detailed information on the geology, depth and location of preexisting wells.  This rule will take effect on June 24, 2015, although it is the subject of several pending lawsuits recently filed by industry groups and at least three states, alleging that federal law does not give the Bureau of Land Management authority to regulate hydraulic fracturing.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. A draft report is expected to be released for public comment; however the report is still pending. The EPA’s study could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing.

Additionally, Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Certain states, including Texas and Colorado, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. For example, in October 2011, the Louisiana Department of Natural Resources adopted new rules requiring the public disclosure of the composition and volume of fracturing fluids used in hydraulic fracturing operations. Also, October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, amongst other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed, new disposal well. The disposal well rule amendments also clarify the Commission’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The disposal well rule amendments became effective November 17, 2014. Furthermore, in May 2013, the Texas Railroad Commission adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill wells. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

 

 

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(a) Recent sales of unregistered securities.

None.

(b) Use of proceeds.

None.

(c) Purchases of equity securities by the issuer and affiliated purchasers.

 

 

 

None.

 

 

Not applicable.

 

 

None.

 

 

The information required by this Item 6. Exhibits is set forth in the Exhibit Index accompanying this quarterly report on Form 10-Q, which is incorporated herein by reference.

 

 

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

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EXHIBIT INDEX

 

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