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 September 30, 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 October 31, 2015, the registrant had 205,314,453 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 provisions 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 initial 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 and nine months ended September 30, 2015 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated 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 $78.4 million in cash and certain properties in North Louisiana (the “Property Swap”) for comparability purposes. Our equity statement reflects a $127.1 million equity transfer from stockholders’ equity to noncontrolling interest related to this transaction.

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, income taxes and asset retirement obligations.

 

Note 2. Summary of Significant Accounting Policies

A discussion of our critical accounting policies and estimates is included in our Current Report on Form 8-K filed on July 8, 2015 (our “Recast Form 8-K”).  Our Recast Form 8-K was filed to retrospectively revise certain historical segment financial information to give effect to the Property Swap for comparability purposes and to include a new note containing condensed consolidating financial information.

Accrued liabilities

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

Supplemental Cash Flow Information

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

Income Tax

MRD is a corporation subject to federal and certain state income taxes. 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. MRD’s 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. 

MRD reported no liability for unrecognized tax benefits as of September 30, 2015 and expects no significant change to the unrecognized tax benefits in the next twelve months. 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

MRD’s effective tax rate for the three and nine months ended September 30, 2015 was negative 67.1% and negative 24.3%, respectively, and the effective tax rate for the three and nine months ended September 30, 2014 was 18.7% and negative 1.5%, respectively. The effective tax rate for the three and nine months ended September 30, 2014 and 2015 differs from the statutory federal income tax rate primarily due to the following recurring items:

MRD reported a $38.8 million increase to equity during the nine months ended September 30, 2015, of which $4.4 million was associated with the estimated deferred tax effects included in equity in connection with its initial public offering and $34.4 million was attributable to the deferred tax effects of the property exchanges under common control including certain oil and gas properties in East Texas that MEMP acquired from MRD in February 2015. 

New Accounting Pronouncements

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

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

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

In August 2015, the FASB issued an accounting standards update that incorporates SEC guidance clarifying that debt issuance costs related to line-of-credit arrangements can be deferred and presented as an asset that is subsequently amortized over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement.

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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

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

Transaction-related costs, which include costs associated with acquisitions and divestitures, are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):

2015 Acquisitions

Subsequent event. On October 22, 2015, MRD closed a transaction to acquire certain producing and non-producing oil and natural gas properties in North Louisiana from a third party for approximately $284.0 million, subject to customary post-closing adjustments.

2015 Divestitures

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

2014 Acquisitions

On March 25, 2014, MEMP closed a transaction to acquire certain oil and natural gas producing properties in the Eagle Ford from a third party for approximately $168.1 million, including customary post-closing adjustments (the “Eagle Ford Acquisition”).

On July 1, 2014, MEMP closed a transaction to acquire certain oil and natural gas liquids properties in Wyoming from a third party for approximately $906.1 million, including customary post-closing adjustments (the “Wyoming Acquisition”).

The following unaudited pro forma combined results of operations are provided for the nine months ended September 30, 2014 as though the Wyoming Acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Company and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

 

 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

2014 Divestitures

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

 

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), restricted investments and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at September 30, 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 September 30, 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 September 30, 2015 and December 31, 2014 for each of the fair value hierarchy levels:

 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

See Note 5 for additional information regarding our derivative instruments.

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:

 

 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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 September 30, 2015, MEMP had net derivative assets of $663.9 million. After taking into effect netting arrangements, MEMP had counterparty exposure of $345.9 million related to its derivative instruments of which $115.3 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 $320.3 million against amounts outstanding under its revolving credit facility at September 30, 2015. At September 30, 2015, MRD had net derivative assets of $343.6 million. After taking into effect netting arrangements, MRD had counterparty exposure of $277.9 million related to derivative instruments of which $91.4 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 $65.7 million against amounts outstanding under its revolving credit facility at September 30, 2015. See Note 8 for additional information regarding our revolving credit facilities.

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 nine months ended September 30, 2015 is net of deferred premiums of $7.1 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 September 30, 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 September 30, 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 September 30, 2015, we had the following interest rate swap open positions:

 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Balance Sheet Presentation

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at September 30, 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.

 

(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 periods indicated (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 nine months ended September 30, 2015 (in thousands):

 

 

 

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 7. Restricted Investments

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with 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:

 

 

 

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):

 

 

On September 18, 2015, the borrowing base under the MRD revolving credit facility was increased to $1.0 billion in connection with the semi-annual borrowing base redetermination by the lenders, and can increase to $1.05 billion, subject to certain conditions, if MRD consummates a certain potential acquisition before December 31, 2015, as acknowledged by the parties in the fifth amendment to the revolving credit agreement.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Subsequent event. On November 4, 2015, MEMP’s borrowing base under its revolving credit facility was redetermined in connection with the semi-annual borrowing base redetermination by the lenders and decreased to approximately $1.18 billion.

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:

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 nine months ended September 30, 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.

On September 25, 2015, MRD issued 13,800,000 shares of common stock (including 1,800,000 shares of common stock sold pursuant to the full exercise of the underwriters’ option to purchase additional shares of common stock) to the public generating total net proceeds of approximately $238.4 million after deducting underwriting discounts and offering expenses. The net proceeds from the equity offering were used to temporarily pay down our revolving credit facility as of September 30, 2015 and subsequently re-borrowed to fund a portion of the purchase price of the North Louisiana Acquisition that closed on October 22, 2015.

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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.

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. The Company did not repurchase any shares of common stock under this program through September 30, 2015.

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 nine months ended September 30, 2015, MEMP repurchased 3,547,921 common units under its repurchase program for an aggregate price of $52.8 million. MEMP has retired all common units repurchased and those common units are no longer issued or outstanding.

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

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

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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:

 

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 $28.1 million at September 30, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.66 years.

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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 $20.0 million at September 30, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.03 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 $5.0 million and $31.3 million of compensation expense for the three and nine months ending September 30, 2015, respectively, offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $72.7 million as of September 30, 2015 will be recognized over the remaining expected service period of 1.67 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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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 September 30, 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 and nine months ended September 30, 2015, MRD paid approximately $4.8 million and $6.7 million, respectively to Cretic Energy Services, LLC, an NGP affiliated company, for services related to our drilling and completion activities.

During the three and nine months ended September 30, 2015, MRD paid approximately $1.0 million and $1.2 million, respectively to Multi-Shot, LLC, an 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 an NGP affiliated company for $3.3 million.

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

 

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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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.

WildHorse Management Services Agreement

A discussion of the WildHorse and WHR II management services and related agreements is included in our Recast Form 8-K. These agreements were terminated in connection with our initial public offering.

Midstream Agreements

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 became operational on June 1, 2015, it began to 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 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 was declared operational, we became 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 was declared operational. Once the second plant was declared operational in October 2015, we became 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 was declared operational, we began to 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 was declared operational. Once the second processing plant was declared operational, we became obligated to 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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Similarly, under the GTA which commences 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 produced on our behalf. Under the TSA, which commences concurrently with the operational dates of the two processing plants, PennTex Operating will be entitled to a commodity usage charge of $0.04 per gallon for all volumes of 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).

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

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.

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. Effective July 1, 2015, the fee was reduced to $0.40 per barrel for each barrel of water delivered to Classic Pipeline.

In February 2015, 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 consolidated 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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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

 

Calculation of Reportable Segments’ Adjusted EBITDA

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

 

 

 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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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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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NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

 

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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 September 30, 2015 and December 31, 2014, we had $0.6 million and $2.1 million of environmental reserves recorded on our balance sheets, respectively.

Midstream Agreements

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 September 30, 2015 (in thousands):

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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 September 30, 2015, the maximum remaining obligation net to REO’s interest was approximately $5.2 million.

Processing Plant Expansions by Third Party Gatherer

A discussion of processing plant expansions by a third party gatherer is included in our Recast Form 8-K.

Related Party Agreements

See Note 13 for additional information.

 

Note 16. Condensed Consolidating Financial Information  

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

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

 

 

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Note 17. Subsequent Events

MRD Purchase of Oil and Natural Gas Properties in Louisiana

For additional information, see Note 3.

MEMP Borrowing Base Redetermination

For additional information, see Note 8.

MEMP November 2015 Beta Acquisition

On November 3, 2015, MEMP completed an acquisition of the remaining interests in its oil and gas properties offshore Southern California (the “Beta properties”) from a third party for approximately $101.0 million, subject to customary post-closing adjustments.  

MEMP first acquired its interests in the Beta properties in December 2012.  The acquired interests primarily consist of the 48.25% remaining working interests in three Pacific Outer Continental Shelf blocks in the Beta Field, which includes 58 gross wells, that are located in federal waters approximately eleven miles offshore the Port of Long Beach, California.  The acquired interests also include the 48.25% remaining interest in associated facilities including (i) two combined production and drilling platforms (ii) one production processing platform, (iii) a 17.5 mile long 16-inch diameter oil pipeline and (iv) an onshore pump station, tankage and metering facility.  

 

 

 

 

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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, our Recast Form 8-K filed with the SEC on July 8, 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 currently believe we will continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosures in the event there is a reconsideration event that triggers deconsolidation.

Recent Developments

North Louisiana Acquisition

In October 2015, we closed a transaction to acquire producing and non-producing properties in North Louisiana, including approximately 45,807 gross (45,121 net) acres for approximately $284.0 million, subject to customary post-closing adjustments, from a third party (the “North Louisiana Acquisition”). The acquisition has an effective date of August 1, 2015.  We financed the North Louisiana Acquisition with the net proceeds from our September 2015 equity offering (discussed below) and borrowings under our revolving credit facility.

September 2015 Equity Offering

In September 2015, we issued 13,800,000 shares of our common stock in an underwritten public offering (which included 1,800,000 shares sold pursuant to the option to purchase additional shares of our common stock granted by us to, and exercised in full by, the underwriter). The aggregate net proceeds from our September 2015 equity offering were approximately $238.4 million after deducting underwriting discounts and commissions and estimated offering expenses. The net proceeds from the equity offering were used to temporarily pay down our revolving credit facility as of September 30, 2015 and subsequently re-borrowed to fund a portion of the purchase price of the North Louisiana Acquisition that closed on October 22, 2015.

Amendments to MRD Revolving Credit Facility and Borrowing Base Redeterminations

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.

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In September 2015, we entered into a fifth amendment to our revolving credit facility to, among other things, increase (i) the borrowing base under our revolving credit facility from $725.0 million to $1.0 billion and (ii) the aggregate elected commitment amounts to $1.0 billion. If the Company consummates a potential acquisition (unrelated to the North Louisiana Acquisition) prior to December 31, 2015 and subject to certain conditions, then the fifth amendment would also increase the borrowing base and the aggregate elected commitment amounts to $1.05 billion effective immediately before consummation of such acquisition.

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 West Louisiana for MEMP’s North Louisiana oil and gas properties and approximately $78.4 million in cash. Terms of the transaction were approved by our Board and by its conflicts committee, which is comprised entirely of independent directors. The transaction had an effective date of January 1, 2015.

MEMP November 2015 Beta Acquisition

In November 2015, MEMP completed an acquisition of the remaining interests in its oil and gas properties offshore Southern California (the “Beta properties”) from a third party for approximately $101.0 million, subject to customary post-closing adjustments.

MEMP first acquired its interests in the Beta properties in December 2012.  The acquired interests primarily consist of the 48.25% remaining working interests in three Pacific Outer Continental Shelf blocks in the Beta Field, which includes 58 gross wells, that are located in federal waters approximately eleven miles offshore the Port of Long Beach, California.  The acquired interests also include the 48.25% remaining interest in associated facilities including (i) two combined production and drilling platforms (ii) one production processing platform, (iii) a 17.5 mile long 16-inch diameter oil pipeline and (iv) an onshore pump station, tankage and metering facility.  

MEMP Semi-Annual Borrowing Base Redeterminations

In November 2015, 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 $1.30 billion to approximately $1.18 billion. The new borrowing base became effective on November 4, 2015.  In March 2015, the borrowing base under its revolving credit facility decreased from $1.44 billion to $1.3 billion. The borrowing base reductions were primarily the result of the deterioration of commodity prices in the oil and natural gas industry.

MEMP Conversion of Subordinated Units

In February 2015, the subordination period for the 5,360,912 MEMP subordinated units ended. All of the subordinated units, which were owned by MRD Holdco, converted to common units on a one-to-one basis at the end of the subordination period and were then sold by MRD Holdco during the second quarter of 2015.

MEMP Repurchase Program

In December 2014, the board of directors of MEMP’s general partner authorized the repurchase of up to $150.0 million of MEMP’s common units (“MEMP Repurchase Program”).  In 2015, MEMP repurchased $52.8 million of common units through October 31, 2015, which represents a repurchase and retirement of 3,547,921 common units under the MEMP Repurchase Program.

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 $78.4 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 Partners LLC (“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.

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

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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Reserves Sensitivity

Historically, commodity prices have been extremely volatile and we expect this volatility to continue for the foreseeable future. For example, for the five years ended December 31, 2014, the NYMEX-WTI oil future price ranged from a high of $113.93 per Bbl to a low of $53.27 per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $6.15 per MMBtu to a low of $1.91 per MMBtu. For the nine months ended September 30, 2015, the West Texas Intermediate posted price ranged from a high of $61.43 per Bbl on June 10, 2015 to a low of $38.24 per Bbl on August 24, 2015 and the Henry Hub spot market price ranged from a high of $3.233 per MMBtu on January 15, 2015 to a low of $2.490 per MMBtu on April 27, 2015. NGL prices have also suffered significant recent declines. The continuation of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

We are unable to predict future commodity prices with any greater precision than the futures market. To quantify the effect of changes in the current pricing environment on the quantities of our year-end 2014 reported proved reserves, we re-ran our December 31, 2014 reserve report using September 30, 2015 NYMEX forward strip pricing. If we had used NYMEX forward strip pricing as of September 30, 2015 to determine our proved reserves as of December 31, 2014, our estimated proved reserves as of December 31, 2014 would have been 1,595 Bcfe, which is 2% less than the 1,632 Bcfe reported as of December 31, 2014 in our Annual Report on Form 10-K for the year ended December 31, 2014. This calculation strictly isolates the potential impact of commodity prices on our estimated proved reserves. Other than the price adjustment, we did not re-engineer our estimated proved reserves to account for cost reductions or any other factors impacting the estimation of proved reserves. For example, this estimate does not give effect to any production or drilling or completion activity that has occurred since December 31, 2014. This estimate was prepared by our internal reserve engineers and has not been audited or reviewed by our independent reserve engineers.

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 combined results of operations for the three and nine months ended September 30, 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 owned certain immaterial leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owned 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 and were then sold by MRD Holdco during the second quarter of 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 $78.4 million in cash and certain properties in North Louisiana.

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Three Months Ended September 30, 2015 Compared to the Three Months Ended September 30, 2014

The MRD Segment recorded net income of $56.6 million during the three months ended September 30, 2015 compared to net income of $10.8 million during the three months ended September 30, 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 $245.6 million during 2015. Average outstanding borrowings under our revolving credit facility were $100.3 million during 2014. For both 2015 and 2014, we had an average of $600.0 million aggregate principal amount of the MRD Senior Notes issued and outstanding.

Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 30, 2014

The MRD Segment recorded net income of $80.2 million during the nine months ended September 30, 2015 compared to net loss of $934.5 million during the nine months ended September 30, 2014.

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Average outstanding borrowings under our revolving credit facility were $189.8 million during 2015. Average outstanding borrowings under WildHorse Resources’ revolving credit facility and our revolving credit facility were $206.5 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 $214.1 million aggregate principal amount of the PIK notes issued and outstanding, an average of $201.2 million aggregate principal outstanding for the WildHorse Resources’ second lien term facility, and an average of $600.0 million aggregate principal amount of the MRD Senior Notes issued and outstanding.

MEMP Segment

The MEMP Segment’s combined results of operations for the three and nine months ended September 30, 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 September 30, 2015 Compared to the Three Months Ended September 30, 2014

A net loss of $192.0 million was recorded for the three months ended September 30, 2015, primarily due to significant losses related to impairments offset by gains on commodity derivative instruments, compared to a net income of $101.3 million recorded during the three months ended September 30, 2014.

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Average outstanding borrowings under MEMP’s revolving credit facility were $684.2 million during 2015 compared to $679.2 million during 2014. For 2015, MEMP had an average of $1.2 billion aggregate principal amount of its senior notes issued and outstanding. For 2014, MEMP had an average of $1.1 billion aggregate principal amount of its senior notes issued and outstanding.

Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 30, 2014

A net loss of $468.5 million was generated for the nine months ended September 30, 2015, primarily due to impairment charges partially offset by significant gains on commodity derivative instruments, compared to a net loss of $43.2 million generated for the nine months ended September 30, 2014.

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Average outstanding borrowings under MEMP’s revolving credit facility were $607.1 million during 2015 compared to $421.9 million during 2014. For 2015, MEMP had an average of $1.2 billion aggregate principal amount of its senior notes issued and outstanding. For 2014, MEMP had an average of $839.2 million aggregate principal amount of its 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 North Louisiana 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.

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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 permit us to complete our remaining 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 can provide no assurance that operations and other needed capital will be available on acceptable terms, or at all.

As of September 30, 2015, we had $874.0 million of available borrowing capacity under our revolving credit facility and $6.8 million of cash and cash equivalents. As of September 30, 2015, we had a working capital balance of $44.3 million. We believe the available borrowings under our revolving credit facility provides sufficient liquidity to finance anticipated working capital and capital expenditure requirements. We borrowed $261.0 million in connection with the closing of the North Louisiana acquisition.

Capital Budget

For the nine months ended September 30, 2015, MRD Segment’s total capital expenditures, including unproved leasehold, were $460.5 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 $1.0 billion as of September 30, 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 September 2015, the borrowing base under our revolving credit facility was increased to $1.0 billion. If the Company consummates a potential acquisition (unrelated to the North Louisiana Acquisition) prior to December 31, 2015 and subject to certain conditions, then the fifth amendment would also increase the borrowing base and the aggregate elected commitment amounts to $1.05 billion effective immediately before consummation of such acquisition. 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 September 30, 2015.

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

MRD Senior Notes

As of September 30, 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 borrowing base of $1.3 billion as of September 30, 2015 that matures in March 2018 and is guaranteed by MEMP and all of its current and future subsidiaries (other than certain immaterial subsidiaries). As of November 4, 2015, MEMP’s borrowing base was reduced to approximately $1.18 billion. See Note 8 under “Item 1. Financial Statements” for additional information regarding MEMP’s revolving credit facility.

Senior Notes

As of September 30, 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.

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As of September 30, 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.

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 September 30, 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 September 30, 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.

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MRD Segment

Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 30, 2014

Operating Activities. Net cash flows provided by operating activities were $251.8 million during 2015 compared to $155.5 million during 2014. Production increased 37.2 Bcfe (approximately 75%) and average realized sales price decreased $2.82 per Mcfe as previously discussed under “Results of Operations—MRD Segment.” Cash paid for interest during 2015 was $17.7 million compared to $35.5 million during 2014 and cash settlements on commodity derivatives were $119.2 million higher in 2015. In 2014, $26.7 million was paid related to the WildHorse Resources incentive units and $30.2 million was paid for debt extinguishment costs.

Investing Activities. Total cash used in investing activities was $456.7 million during 2015 compared to $187.5 million for the same period in 2014. Cash used for additions to oil and gas properties was $438.3 million during 2015 compared to $240.2 million for the same period in 2014, which consisted primarily of drilling and completion activities in North Louisiana. Cash used for acquisition of oil and natural gas properties was $7.3 million during 2015 which was used to acquire oil and natural gas properties from a third party. Additions to other property and equipment were $3.8 million which consisted primarily of computer hardware, software, and other leased office space build out during 2015. The $9.1 million of additions to other property and equipment during 2014 was primarily related to new office space costs. MRD made an earnest money deposit of $21.3 million during 2015 related to its North Louisiana Acquisition. Distributions of $0.2 million and $6.0 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.  On April 17, 2015, we sold certain oil and natural gas properties to a third party in Colorado and Wyoming for approximately $13.6 million. On May 9, 2014, Black Diamond sold certain producing and non-producing properties in the Mississippian oil play of Northern Oklahoma to a third party for cash consideration of approximately $6.7 million. There was a decrease in restricted cash of $49.9 million in 2014, which was primarily due to $50.0 million being released from the debt service reserve account associated with the PIK notes.

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Financing Activities.  Net repayments under our revolving credit facility were $57.0 million during 2015.  Amounts borrowed under our revolving credit facility were primarily used for additions to oil and natural gas properties, to fund the earnest money deposit for the North Louisiana Acquisition, and general corporate purposes, including working capital.  Net repayments under revolving credit facilities were $175.1 million during 2014.  Amounts borrowed under our revolving credit facility were primarily incurred to repay the amounts outstanding under WildHorse Resources’ credit facilities in connection with the closing of our initial public offering. WildHorse Resources primarily utilized its revolving credit facility during 2014 to repurchase net profits interests from an affiliate of NGP.

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

On June 18, 2014, we completed our initial public offering pursuant to which we sold 21,500,000 shares of our common stock to the public at an offering price of $19.00 per share. After deducting underwriting discounts and commissions of $23.0 million and additional offering expenses of $5.2 million, the net proceeds from our initial public offering were approximately $380.3 million. We used approximately $360.0 million of our initial public offering proceeds to redeem the PIK notes on June 27, 2014, of which $351.8 million was classified as a financing activity and the remaining $8.2 million was classified as an operating activity representing interest expense.

On September 25, 2015, MRD issued 13,800,000 shares of common stock (including 1,800,000 shares of common stock sold pursuant to the full exercise of the underwriters’ option to purchase additional shares of common stock) to the public generating total net proceeds of approximately $238.4 million after deducting underwriting discounts and offering expenses. The net proceeds temporarily reduced borrowings outstanding under our revolving credit facility.

Distributions to NGP affiliates related to the purchase of assets were primarily related to WildHorse Resources’ February 2014 acquisition of net profits interests in the Terryville Complex from an affiliate of NGP for $63.4 million. MRD Royalty also acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from an affiliate of NGP for $3.3 million in March 2014.

Distributions to NGP affiliates related to the sale of assets were $32.8 million during 2014. WildHorse Resources sold its subsidiary, WHR Management Company, LLC to an affiliate of the Funds for approximately $0.2 million and $33.0 million of cash was a component of the net book value transferred.

Distributions to MRD Holdco during 2014 were $59.8 million. Approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014 was distributed to MRD Holdco in connection with our initial public offering. We also reimbursed MRD LLC for the approximately $17.2 million interest payment that it made on the PIK notes on June 15, 2014, which was distributed to MRD Holdco. Remaining cash of $32.8 million released from the debt service reserve account in connection with the redemption and discharge of the PIK notes was also distributed to MRD Holdco. Bluestone distributed $3.1 million to MRD Holdco in connection with our initial public offering and restructuring transactions.

The MRD Segment received $78.4 million from the MEMP Segment in connection with the Property Swap. MRD made deemed distributions of $1.9 million and $2.8 million to MEMP related to the properties MEMP acquired in the Property Swap transaction during 2015 and 2014, respectively. The MRD Segment received $43.8 million from the MEMP Segment, of which $33.9 million was received in connection with MEMP’s acquisition of certain oil and gas properties in East Texas during 2014 and $9.9 million was a deemed contribution related to the properties MEMP acquired in the Property Swap.

Total payments remitted for employees’ tax obligations to the appropriate taxing authorities were approximately $1.2 million during 2015 upon vesting of the restricted common stock. The Company repurchased 2,888,684 shares of its common stock under its December 2014 repurchase program for an aggregate price of $50.0 million during 2015, which exhausted the December 2014 repurchase program. 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 $1.5 million and $18.9 million were incurred during 2015 and 2014, respectively.

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MEMP Segment

Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 30, 2014

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities decreased by $24.4 million and net income decreased by $425.3 million. Production increased 9.2 Bcfe (approximately 15%) while average realized sales price decreased $3.10 per Mcfe. Net cash provided by operating activities included a $194.0 million period-to-period increase in cash settlements received on expired commodity derivative instruments. The period-to-period increases in cash settlements received on expired commodity derivatives partially offset decreased revenues and increased operating costs as previously discussed under “—Results of Operations—MEMP Segment.”

Investing Activities. Net cash used in investing activities during 2015 was $196.5 million, of which $6.1 million was used to acquire oil and natural gas properties from a third party and $196.1 million was used for additions to oil and natural gas properties. Cash used in investing activities during 2014 was $1.3 billion, of which $1.1 billion was used to acquire oil and natural gas properties from third parties and $217.6 million was used for additions to oil and natural gas properties. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. Additions to restricted investments were $3.9 million during 2015 compared to $2.9 million during 2014. MEMP received a post-closing settlement receipt of $9.6 million related to its July 2014 Wyoming acquisition during 2015.

Financing Activities. Distributions to partners during 2015 were $138.3 million compared to $107.1 million during 2014, of which the MRD Segment received $0.2 million during 2015 compared to $6.1 million during 2014. The MEMP Segment distributed $78.4 million to the MRD Segment in connection with the Property Swap acquisition. MEMP received a contribution of $1.9 million and $2.8 million from the MRD Segment related to the properties MEMP acquired in the Property Swap transaction during 2015 and 2014, respectively. The MEMP Segment distributed $43.8 million to the MRD Segment, of which $33.9 million was related to the acquisition of certain oil and gas properties in East Texas during 2014 by MEMP and $9.9 million was a deemed contribution related to the properties MEMP acquired in the Property Swap.

MEMP issued a total of 24,840,000 common units generating gross proceeds of approximately $553.3 million offset by approximately $12.2 million of costs incurred in conjunction with the issuance of common units during 2014. The net proceeds from these issuances were primarily used to repay borrowings under MEMP’s revolving credit facility. Proceeds of $492.4 million from the issuances of the 2022 Senior Notes during 2014 were also used to repay borrowings outstanding under MEMP’s revolving credit facility.

MEMP had net borrowings of $284.0 million under its revolving credit facility during 2015 that were primarily used to fund the Property Swap acquisition, common unit repurchases and to fund MEMP’s drilling program. MEMP had net borrowings of $198.0 million under its revolving credit facility during 2014 that were used primarily to fund its March 2014 Eagle Ford acquisition, the July 2014 Wyoming acquisition and to fund MEMP’s drilling program.

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MEMP repurchased $54.2 million in common units during 2015, which represents a repurchase and retirement of 3,641,721 common units under the MEMP Repurchase Program (including common unit repurchases of $1.4 million, representing 93,800 common units, accrued at December 31, 2014). 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 nine months ended September 30, 2015, there were no significant changes in our consolidated contractual obligations from those reported in our Recast Form 8-K filed with the SEC on July 8, 2015, except for the addition of the midstream service agreements with PennTex. For more information, see Note 13 of the Notes to the Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

Off–Balance Sheet Arrangements

As of September 30, 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 September 30, 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 September 30, 2015.

At September 30, 2015, we had $126.0 million of Eurodollar borrowings outstanding under our revolving credit facility, with an interest rate of LIBOR plus 1.50%, or 1.69%. 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 September 30, 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 September 30, 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 September 30, 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 and our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2015 filed with the SEC on May 11, 2015.

The standardized measure of our estimated proved reserves and our PV-10 as of December 31, 2014 and the estimated proved and possible reserves attributable to certain of our properties in North Louisiana as of July 31, 2015 may be higher than the current market value of our estimated proved oil and natural gas reserves.

The present value of future net cash flows from our proved reserves as of December 31, 2014, or standardized measure, and our PV-10 may not be the current market value of our estimated natural gas and oil reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board, we base the estimated discounted future net cash flows from our proved reserves on the 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Our estimated proved reserves as of December 31, 2014 and related PV-10 and Standardized Measure were calculated under SEC rules using twelve-month trailing average benchmark prices of $94.99 per barrel of oil (WTI) and $4.35 per MMBtu (Henry Hub spot). Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. On September 30, 2015, the prompt month NYMEX-WTI futures price for crude oil was $45.71 per Bbl and the prompt month NYMEX-Henry Hub futures price of natural gas was $2.52 per MMBtu. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. Using more recent prices in estimating our proved reserves, without giving effect to any acquisitions or development activities we have executed during 2015, would likely result in a reduction in proved reserve volumes due to economic limits, which would reduce the PV-10 and standardized measure of our proved reserves.

Similarly, the estimated proved and possible reserves attributable to the approximately 45,807 gross (45,121 net) acres we acquired in the North Louisiana Acquisition and the approximately 6,521 net acres we acquired in 2015 through our organic leasing efforts in and around the properties acquired in the North Louisiana Acquisition (collectively, the “Acquisition Acreage”) and associated net value of future net cash flows may not be the current market value of such estimated reserves. Additionally, the development of possible reserves will require additional capital expenditures compared to proved reserves, and possible reserves are less certain to be recovered than proved reserves. The estimated proved and possible reserves attributable to the Acquisition Acreage as of July 31, 2015 and related possible reserve PV-10 were calculated under SEC rules using twelve-month trailing average benchmark prices of $64.15 per barrel of oil (WTI) and $3.25 per MMBtu (Henry Hub spot).

 

 

(a) Recent sales of unregistered securities.

None.

(b) Use of proceeds.

None.

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

During the quarterly period ended September 30, 2015, there were no repurchases of our common stock.

 

 

None.

 

 

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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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