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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10–Q

 

For the quarterly period ended September 30, 2016

OR

For the transition period from                      to                     .

Commission File Number: 001-35364

 

MEMORIAL PRODUCTION PARTNERS LP

(Exact name of registrant as specified in its charter)

 

Registrant’s telephone number, including area code: (713) 490-8900

 

 

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  ☑    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  ☑    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  ☑

As of October 28, 2016, the registrant had 83,831,331 common units outstanding.

 

 

 

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MemORIAL PRoducTION PARTNERS LP

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.

API Gravity: A system of classifying oil based on its specific gravity, whereby the greater the gravity, the lighter the oil.

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

Bbl/d: One Bbl per day.

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.

Development Project: A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

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 a working interest.

ICE: Inter-Continental Exchange.

MBbl: One thousand Bbls.

MBoe: One thousand barrels of oil equivalent. One Boe is calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

MBoe/d: One thousand Boe per day.

MBtu: One thousand Btu.

Mcf: One thousand cubic feet of natural gas.

Mcf/d: One Mcf per day.

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 to 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.

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OPIS: Oil Price Information Service.

Probabilistic Estimate: The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrences.

Proved Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

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.

Realized Price: The cash market price less all expected quality, transportation and demand adjustments.

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.

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.

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 limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

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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.

Workover: Operations on a producing well to restore or increase production.

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 on Form 10-Q contains “forward-looking statements” that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

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These types of statements, other than statements of historical fact included in this 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,” “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 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 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 “Part I—Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2015 (“2015 Form 10-K”), our Current Report on Form 8-K filed with the SEC on May 25, 2016 and “Part II—Item 1A. Risk Factors” appearing within this report and elsewhere in this report. All forward-looking statements speak only as of the date of this 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 PRODUCTION PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding units)

 

 

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

 

 

 

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MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS

(In thousands, except per unit amounts)

  

 

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

 

 

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MEMORIAL PRODUCTION PARTNERS LP

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 PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

(In thousands)

  

 

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

 

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 1. Organization and Basis of Presentation

General

Memorial Production Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MEMP.” Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Partnership” are intended to mean the business and operations of Memorial Production Partners LP and its consolidated subsidiaries.  

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment as the economic environments are not different within the operation of our oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, Wyoming and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Partnership’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells.

Unless the context requires otherwise, references to: (i) “our general partner” or “MEMP GP” refer to Memorial Production Partners GP LLC, our general partner and wholly-owned subsidiary; (ii) “Memorial Resource” refer collectively to Memorial Resource Development Corp. and its subsidiaries; (iii) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P.; (iv) “OLLC” refer to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties; (v) “Finance Corp.” refer to Memorial Production Finance Corporation, our wholly-owned subsidiary, whose activities are limited to co-issuing our debt securities and engaging in other activities incidental thereto; and (vi) “NGP” refer to Natural Gas Partners.

On April 27, 2016, we entered into an agreement pursuant to which the Partnership agreed to acquire, among other things, all of the equity interests in our general partner, MEMP GP, from Memorial Resource (the “MEMP GP Acquisition”) for cash consideration of approximately $0.8 million. MEMP GP held an approximate 0.1% general partner interest and 50% of the incentive distribution rights ("IDRs") in us. In conjunction with the MEMP GP Acquisition, on April 27, 2016, we also entered into an agreement with an NGP affiliate pursuant to which we agreed to acquire the other 50% of the IDRs. The acquisition was accounted for as an equity transaction and no gain or loss was recognized as a result of the acquisition.

In connection with the closing of the transactions on June 1, 2016, our partnership agreement was amended and restated to, among other things, (i) convert the 0.1% general partner interest in the Partnership held by MEMP GP into a non-economic general partner interest, (ii) cancel the IDRs, and (iii) provide that the limited partners of the Partnership will elect the members of MEMP GP’s board of directors beginning with the annual meeting in 2017. In addition, we terminated the omnibus agreement under which Memorial Resource provided management, administrative and operations personnel to us and our general partner, and we entered into a transition services agreement with Memorial Resource to manage certain post-closing separation costs and activities. See Note 11 and Note 12 for additional information regarding the MEMP GP Acquisition and the transition services agreement.

Liquidity

As of September 30, 2016, we were in compliance with our financial covenants under our revolving credit facility. Effective October 28, 2016, in connection with the semi-annual borrowing redetermination by the lenders under our revolving credit facility, the borrowing base under our revolving credit facility was reduced to $740.0 million and will automatically be further reduced to $720.0 million on December 1, 2016. With our borrowing base at such levels, we will have limited to no available borrowing capacity and will likely be unable to remain in compliance with certain financial covenants under our revolving credit facility as early as the fourth quarter of 2016.

In addition, if we are unable to remain in compliance with the covenants under our revolving credit facility or the indentures governing our senior notes, or a cross-default occurs under either, absent relief from our lenders or noteholders, as applicable, we may be forced to repay or refinance such indebtedness and we may incur other damages. Upon the occurrence of an event of default, the lenders under our revolving credit facility or holders of our senior notes, as applicable, could elect to declare all amounts outstanding immediately due and payable or seek other remedies and the lenders could terminate all commitments to extend further credit under our revolving credit facility. If an event of default occurs under our revolving credit facility or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding or seek other remedies, we will not have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there would be substantial doubt regarding our ability to continue as a going concern. We might also be required to seek relief under the Bankruptcy Code.  See Note 7 for more information.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Previous Owners

References to “the previous owners” for accounting and financial reporting purposes refer to certain oil and gas properties primarily located in East Texas and West Louisiana that the Partnership acquired on February 23, 2015 from certain operating subsidiaries of Memorial Resource in exchange for cash and certain of our oil and natural gas properties primarily located in North Louisiana for periods after common control commenced through the date of acquisition. We refer to this transaction as the “Property Swap.” The acquired East Texas oil and natural gas properties were owned by Classic Hydrocarbons Holdings, L.P. or its subsidiaries.  The Property Swap was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information were retrospectively revised to give effect to the Property Swap as if the Partnership owned the assets for periods after common control commenced through the acquisition date.

Basis of Presentation

Our consolidated results of operations are presented together with the combined results of operations pertaining to the previous owners. The combined financial statements of the previous owners were derived from their historical accounting records and reflect their historical financial position, results of operations and cash flows. The inclusion of MEMP GP in our consolidated financial statements was effective June 1, 2016 due to the MEMP GP Acquisition. See Note 11 for more information. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation.

Our results of operations for the three and nine months ended September 30, 2016 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the SEC.

All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements.

Use of Estimates

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

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

 

 

Note 2. Summary of Significant Accounting Policies

A discussion of our significant accounting policies and estimates is included in our 2015 Form 10-K.

Accrued Liabilities

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

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Supplemental Cash Flows

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

 

New Accounting Pronouncements

Statement of Cash Flows – Classification of Certain Cash Receipts and Cash Payments. In August 2016, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update to address eight specific cash flow issues with the objective of reducing the current and potential future diversity in practice. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The new guidance requires transition under a retrospective approach for each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures.

Improvements to Employee Share-Based Payment Accounting. In March 2016, the FASB issued an accounting standards update to simplify the guidance on employee share-based payment accounting. The update involves several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification in the statement of cash flows. Entities will no longer record excess tax benefits and certain tax deficiencies in equity. Instead, they will record all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement. In addition, the new guidance eliminates the requirement that excess tax benefits be realized before entities can recognize them and requires entities to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity. Furthermore, the new guidance will increase the amount an employer can withhold to cover income taxes on awards and still qualify for the exception to liability classification for shares used to satisfy the employer’s statutory income tax withholding obligation. The new guidance requires an entity to classify the cash paid to a tax authority when shares are withheld to satisfy its statutory income tax withholding obligation as a financing activity on the statement of cash flows. In addition, entities will now have to elect whether to account for forfeitures on share-based payments by: (i) recognizing forfeitures of awards as they occur or (ii) estimating the number of awards expected to be forfeited and adjusting the estimate when it is likely to change, as is currently required.

The new guidance is effective for reporting periods beginning after December 15, 2016 and interim periods within those fiscal years. Early adoption is permitted, but all of the guidance must be adopted in the same period. For the amendments that change the recognition and measurement of share-based payment awards, the new guidance requires transition under a modified retrospective approach, with a cumulative-effect adjustment made to retained earnings as of the beginning of the fiscal period in which the guidance is adopted. Prospective application is required for the accounting for excess tax benefits and tax deficiencies. Entities should apply the new guidance retrospectively for all periods presented related to the classification of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirements. Entities may apply the presentation changes for excess tax benefits in the statement of cash flows either prospectively or retrospectively. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Leases. In February 2016, the FASB issued a revision to lease accounting guidance. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The revised guidance must be adopted using a modified retrospective transition and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. The Partnership is currently evaluating the standard and the impact on the consolidated financial statements and related footnote disclosures.

Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. In April 2015, the FASB issued an accounting standards update that specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method are also required. The guidance was effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. We adopted this guidance on January 1, 2016. Since the Partnership has historically allocated the earnings (losses) of transferred businesses that occurred in periods before the date of the dropdown transaction entirely to affiliates of the general partner (i.e., the previous owners) and did not adjust previously reported earnings per unit of the limited partners, the impact of adopting this guidance was not material to the Partnership’s financial statements and related disclosures.

Revenue from Contracts with Customers. In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance, requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. The guidance is effective for interim and annual reporting periods beginning after December 15, 2017, and early adoption is permitted. The new standard permits adoption through the use of either the full retrospective approach or a modified retrospective approach. The Partnership is currently evaluating the standard and the impact on the consolidated financial statements and related footnote disclosures.

Presentation of Financial Statements — Going Concern: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. In August 2014, the FASB issued an accounting standards update that requires management to perform interim and annual assessments of whether there are conditions or events that raise substantial doubt of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. Certain disclosures are required if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The guidance is effective for annual periods ending after December 15, 2016, and interim periods thereafter, and with early adoption permitted. The amendments will not impact our financial position or results of operations but will require management to perform a formal going concern assessment. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures.

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

 

 

Note 3. Acquisitions and Divestitures

Related Party Acquisitions

See Note 11 for further information regarding related party acquisitions that have been accounted for as transactions between entities under common control that impact the basis of presentation for the periods presented.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Acquisition and Divestiture related Expenses

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

 

 

2015 Acquisitions

On November 3, 2015, we closed a transaction to acquire the noncontrolling interest in San Pedro Bay Pipeline Company (“SPBPC”) and the remaining interests in our oil and gas properties offshore Southern California (the “Beta Properties”) from a third party (the “2015 Beta Acquisition”), which was discussed in our 2015 Form 10-K. The following unaudited pro forma combined results of operations are provided for the three and nine months ended September 30, 2015 as though the 2015 Beta Acquisition had been completed on January 1, 2014. The unaudited pro forma financial information was derived from the historical consolidated and combined statements of operations of the Partnership 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, (iii) accretion expense associated with asset retirement obligations recorded and (iv) 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.

 

Divestitures

On July 14, 2016, we closed a transaction to divest assets located in Colorado and Wyoming (the “Rockies Divestiture”) for a total proceeds of approximately $16.9 million, including estimated post-closing adjustments, which included $18.1 million in cash and $1.3 million in accounts payable. We recorded a loss of approximately $3.9 million in “(gain) loss on sale of properties” in the accompanying statement of operations. The proceeds from this transaction were used to reduce borrowings under our revolving credit facility. This disposition does not qualify as a discontinued operation.

On June 14, 2016, we closed a transaction to divest assets located in the Permian Basin (the “Permian Divestiture”) for a total purchase price of approximately $36.9 million including estimated post-closing adjustments, which included $36.4 million in cash and $0.5 million in accounts receivable. We recognized a gain of $6.5 million on the sale of properties related to the Permian Divestiture in “(gain) loss on sale of properties” in the accompanying statement of operations. The proceeds from this transaction were used to reduce borrowings under our revolving credit facility. This disposition does not qualify as a discontinued operation.

During the nine months ended September 30, 2016, the Partnership completed other immaterial divestitures for which we recorded a gain of $0.9 million on the sale that is recorded in “(gain) loss on sale of properties” in the accompanying statement of operations.

The income (loss) before income taxes, including the associated (gain) loss on sale of properties, related to the Permian Divestiture and Rockies Divestiture included in the unaudited condensed statements of consolidated and combined operations of the Partnership is as follows (in thousands):

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

 

 

Note 4. Fair Value Measurements of Financial Instruments

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

The carrying values of accounts receivables, accounts payables (including accrued liabilities), 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, 2016 and December 31, 2015. 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 7 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, 2016 and December 31, 2015 were based on estimated forward commodity prices and forward interest rate yield curves. 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, 2016 and December 31, 2015 for each of the fair value hierarchy levels:

 

See Note 5 for additional information regarding our derivative instruments.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

 

 

Note 5. Risk Management and Derivative Instruments

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

Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreement 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 creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into 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. As a result, had all counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $267.0 million against amounts outstanding under our revolving credit facility at September 30, 2016, reducing our maximum credit exposure to approximately $188.7 million, of which approximately $59.9 million was with one counterparty. See Note 7 for additional information regarding our revolving credit facility.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Commodity Derivatives

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

During the nine months ended September 30, 2016, we terminated certain “in-the-money” crude oil and NGL derivatives settling in 2016 and certain crude oil basis swaps settling in 2016 and 2017. We received cash settlements of approximately $39.3 million from the termination of these crude oil and NGL derivatives.

During the nine months ended September 30, 2015, we restructured a portion of our 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 these 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, CIG 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, ICE Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu. At September 30, 2016, we had the following open commodity positions:

 

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Our basis swaps included in the table above are 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 agreement to fixed interest rates. From time to time we enter into offsetting positions to avoid being economically over-hedged. At September 30, 2016, we had the following interest rate swap open positions:

 

Balance Sheet Presentation

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at September 30, 2016 and December 31, 2015. 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 credit agreement.

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

(Gains) Losses on Derivatives

We do not designate derivative instruments as hedging instruments for accounting and financial reporting purposes. Accordingly, all gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations. The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands):  

 

 

 

Note 6. Asset Retirement Obligations

The Partnership’s asset retirement obligations primarily relate to the Partnership’s 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, 2016 (in thousands):

 

 

 

Note 7. Long-Term Debt

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

 

Subsidiary Guarantors

Our outstanding debt securities are, and any debt securities issued in the future will likely be, jointly and severally, fully and unconditionally guaranteed (subject to customary release provisions) by certain of the Partnership’s subsidiaries (collectively, the “Guarantor Subsidiaries”). The Guarantor Subsidiaries are 100% owned by the Partnership. The Partnership has no material assets or operations independent of the Guarantor Subsidiaries and there are no significant restrictions upon the ability of the Guarantor Subsidiaries to distribute funds to the Partnership.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

OLLC Revolving Credit Facility

OLLC is a party to a $2.0 billion revolving credit facility, which is guaranteed by us and all of our current and future subsidiaries (other than certain immaterial subsidiaries).

On April 14, 2016, we entered into a tenth amendment to our credit agreement, dated as of December 14, 2011 (as previously amended, the “Credit Agreement”), by and among the Partnership, OLLC, the administrative agent and the other agents and lenders party thereto (the “Tenth Amendment”). The Tenth Amendment, among other things, amended the Credit Agreement to:

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

We incurred approximately $1.0 million in fees related to the Tenth Amendment which are included as deferred financing costs within “Other long-term assets” in the accompanying balance sheet.

Borrowing Base

Credit facilities tied to borrowing bases are common throughout the oil and gas industry. The borrowing base for our revolving credit facility was the following at the date indicated:

Subsequent Event

On October 28, 2016, we entered into an eleventh amendment to our credit agreement, dated as of December 14, 2011 (as previously amended, the “Credit Agreement”), by and among the Partnership, OLLC, the administrative agent and the other agents and lenders party thereto (the “Eleventh Amendment”). The Eleventh Amendment, among other things, (i) pursuant to a regularly-scheduled semi-annual redetermination of the borrowing base, decreases the borrowing base from $925 million to $740 million, effective as of October 28, 2016, and schedules a further decrease of the borrowing base to $720 million, effective as of December 1, 2016 and (ii) amends the Credit Agreement to add a new event of default limiting the Partnership’s, OLLC and their respective subsidiaries’ ability to call, make or offer to make any redemption of, or make any other payments in respect of the Partnership’s senior unsecured notes if, on a pro forma basis, the Partnership’s and its subsidiaries’ aggregate liquidity (unrestricted cash and cash equivalents plus amounts available to be drawn under the Credit Agreement), is less than $30 million. See Note 1 for additional information regarding liquidity.

Weighted-Average Interest Rates

The following table presents the weighted-average interest rates paid, excluding commitment fees, 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:

 

Letters of Credit

At September 30, 2016, we had $2.4 million of letters of credit outstanding, all related to operations at our Wyoming properties.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Repurchases of Senior Notes

During the three and nine months ended September 30, 2016, the Partnership repurchased on the open market an aggregate principal amount of approximately $1.5 million and $53.7 million, respectively, of its 7.625% senior notes due May 2021. During the nine months ended September 30, 2016, the Partnership repurchased on the open market an aggregate principal amount of $32.0 million of its 6.875% senior notes due August 2022. In connection with the repurchases, the Partnership paid approximately $0.8 million and $41.3 million for the three and nine months ended September 30, 2016, respectively. We recorded a gain on extinguishment of debt of approximately $0.7 million and $42.3 million for the three and nine months ended September 30, 2016, respectively.

During the nine months ended September 30, 2015, the Partnership repurchased on the open market approximately $3.0 million of its 6.875% senior notes due August 2022. In connection with the repurchase, the Partnership paid approximately $2.6 million and recorded a gain on extinguishment of debt of approximately $0.4 million for the nine months ended September 30, 2015.

Subsequent Event

In addition, we elected to defer an approximately $24.6 million interest payment due on November 1, 2016 with respect to the 2021 Senior Notes. The interest payment is subject to a 30-day grace period under the indenture. After the grace period, the failure to pay interest would constitute a default and an event of default under our indentures. During the 30-day grace period, we expect to continue working with our noteholders regarding an effort to develop a comprehensive plan to de-lever the Partnership and strengthen our balance sheet. Failure to pay interest on the 2021 Senior Notes on November 1, 2016 constituted a default and an event of default under our revolving credit facility, which default was waived by the lenders under our revolving credit facility.

On November 1, 2016, the Partnership, OLLC, certain subsidiaries of the Partnership, the administrative agent, and the lenders consenting thereto entered into the limited waiver and twelfth amendment (the “Waiver and Twelfth Amendment”) to the Credit Agreement.

Pursuant to the Waiver and Twelfth Amendment, the requisite lenders under the Credit Agreement agreed to the limited waiver of certain defaults and events of default that will occur under the Credit Agreement as a result of the Partnership’s and Finance Corp’s (collectively, the “Issuers”) election to avail themselves of the 30-day grace period under the indenture governing the Issuers’ 7.625% Senior Notes due May 2021 for the payment of the semi-annual interest payment in respect of such senior notes due November 1, 2016.

Pursuant to the Waiver and Twelfth Amendment, from the date thereof until November 30, 2016 (the “Waiver Period”), the Partnership and OLLC agree to pay 100% of the net cash proceeds from any asset sale, transfer or other disposition (including with respect to notes receivable and accounts receivable) and from the liquidation of any swap transaction or hedge transaction arising under swap or hedge agreements between or among the Partnership, OLLC and/or any other loan party and any lender under the Credit Agreement and/or its affiliates, in each case, to the administrative agent for the ratable account of each lender under the Credit Agreement, for application to the outstanding loans under the Credit Agreement. Amounts so applied will also reduce the aggregate commitments of the lender under the Credit Agreement by an equivalent amount.

Further, pursuant to the Waiver and Twelfth Amendment, the Partnership and OLLC agree, during the Waiver Period, to additional restrictive covenants. These restrictions further limit, until the expiration of the Waiver Period, the ability of, among other things, the Partnership, OLLC and certain of their respective subsidiaries from incurring additional indebtedness, creating liens on assets, paying certain dividends and distributions, making any optional or voluntary payments or redemptions in respect of any other indebtedness, making investments (including in respect of the creation of subsidiaries), entering into certain lease agreements, entering into certain business combinations, entering into any sale-leaseback transaction and entering into certain transactions with affiliates. A failure to comply with these restrictions could result in an event of default under the Credit Agreement. In the event of the occurrence of any such event of default, the debtor’s obligations under the Credit Agreement could, under certain circumstances, become immediately due and payable.

Finally, pursuant to the Waiver and Twelfth Amendment, the Partnership and OLLC agreed to amend, to be effective from and after the date of the Waiver and Twelfth Amendment, the Credit Agreement to increase, from 90% to 95% (or such lesser amount agreed to by the administrative agent in its sole discretion, which lesser amount shall not be less than 92%), the percentage of the total value of OLLC’s and its subsidiary-loan parties’ oil and gas properties subject to a mortgage or similar instruments in favor of the administrative agent. See Note 1 for additional information.

 

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 8. Equity & Distributions

Equity Outstanding

The following table summarizes changes in the number of outstanding units since December 31, 2015:

 

Restricted common units are a component of common units as presented on our unaudited condensed consolidated balance sheets. See Note 10 for additional information regarding restricted common units that were granted during the nine months ended September 30, 2016.

“At-the-Market” Equity Program

On May 25, 2016, the Partnership entered into an equity distribution agreement for the sale of up to $60.0 million of common units under an at-the-market program (the “ATM Program”). Sales of common units, if any, will be made under the ATM Program by means of ordinary brokers’ transactions, through the facilities of the NASDAQ Global Market at market prices, or as otherwise agreed between the Partnership and a sales agent. The Partnership expects to use the net proceeds from any sale of common units for general partnership purposes, which may include repaying or refinancing a portion of our outstanding indebtedness and funding working capital, capital expenditures or acquisitions.

During the three and nine months ended September 30, 2016, the Partnership sold 355,789 and 1,178,102 common units, respectively, under the ATM program. The sale of the units generated proceeds of approximately $0.5 million and $2.1 million for the three and nine months ended September 30, 2016, which was net of approximately $0.2 million and $0.3 million in fees, respectively. At September 30, 2016, approximately $57.6 million of common units remained available for issuance under the ATM Program.

2015 Repurchases of Common Units

During the nine months ended September 30, 2015, we repurchased $52.8 million in common units, which represented a repurchase and retirement of 3,547,921 common units under the December 2014 repurchase program. The December 2014 repurchase program expired in December 2015.

Allocations of Net Income (Loss)

Prior to the MEMP GP Acquisition, net income (loss) attributable to the Partnership was allocated between our general partner and the common unitholders in proportion to their pro rata ownership after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated to our general partner and the Funds. Net income (loss) attributable to acquisitions accounted for as a transaction between entities under common control in a manner similar to the pooling of interest method prior to their acquisition date is allocated to the previous owners since they were affiliates of our general partner. Subsequent to the MEMP GP Acquisition, net income (loss) attributable to the Partnership is allocated entirely to the common unit holders.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Cash Distributions to Unitholders

The following table summarizes our declared quarterly cash distribution rates with respect to the quarter indicated (dollars in millions, except per unit amounts):

 

In October 2016, the board of directors of our general partner suspended distributions on common units primarily due to the current and expected commodity price environment and market conditions and their impact on our future business as well as restrictions imposed by our debt instruments, including our revolving credit facility. The board of directors of our general partner believes the suspension in distributions is in the best interest of the Partnership.  See Note 1 for additional discussions regarding liquidity.

 

 

Note 9. Earnings per Unit

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

 

 

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 10. Unit-Based Awards

Restricted Common Units

The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) for the periods presented:

 

The unrecognized compensation cost associated with restricted common unit awards was $5.1 million at September 30, 2016. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.33 years. Since the restricted common units are participating securities, distributions received by the restricted common unitholders are generally included in distributions to partners as presented on our unaudited condensed statements of consolidated and combined cash flows.

LTIP Modification

On June 1, 2016, in connection with the MEMP GP Acquisition as discussed in Note 1, the board of directors of our general partner approved the acceleration of the vesting schedule of unvested awards under the LTIP for the employees that remained with Memorial Resource. The grant-date fair value compensation cost of approximately $0.1 million was reversed and the modified-date grant fair value compensation cost of $0.5 million was recognized.

On March 9, 2016, certain employees were impacted by an involuntary termination which, upon the approval of the board of directors of our general partner, accelerated the vesting schedule of unvested awards under the LTIP that otherwise would have been forfeited upon an involuntary termination. The acceleration of the LTIP vesting schedule represents an improbable-to-probable modification. The grant-date fair value compensation cost of approximately $0.5 million was reversed and the modified-date grant fair value compensation cost of approximately $0.3 million was recognized.

Phantom Units

The following table summarizes information regarding phantom unit awards granted under the LTIP:

 

Phantom units issued to non-employee directors in January will vest on the first anniversary of the date of grant. Phantom units issued to certain employees in June will vest in substantially equal one-third increments on the first, second, and third anniversaries of the date of grant. The awards included distribution equivalent rights (“DERs”) pursuant to which the recipient will receive a cash payment with respect to each phantom unit equal to any cash distributions that we pay to a holder of a common unit. DERs are treated as additional compensation expense. Upon vesting, the phantom units will be settled through an amount of cash in a single lump sum payment equal to the product of (y) the closing price of our common units on the vesting date and (z) the number of such vested phantom units. In lieu of a cash payment, the board of directors of our general partner, in its discretion, may elect for the recipient to receive either a number of common units equal to the number of such vested phantom units or a combination of cash and common units. For the three and nine months ended September 30, 2016, the phantom units issued are classified as liability awards due to the Partnership not having sufficient common units available under the LTIP to settle in common units upon vesting.

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Compensation Expense

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

 

 

Note 11. Related Party Transactions

Amounts due to Memorial Resource and certain affiliates of NGP at December 31, 2015 are presented within “Accounts payable – affiliates” in the accompanying balance sheets. On June 1, 2016, Memorial Resource and certain affiliates of NGP became unaffiliated entities after we closed the MEMP GP Acquisition, as discussed in Note 1 and Note 12.

NGP Affiliated Companies

During the nine months ended September 30, 2016, we paid less than $0.1 million, to Multi-Shot, LLC, an NGP affiliate company, for services related to our drilling and completion activities. During the three and nine months ended September 30, 2015, we paid less than $0.1 million and $0.3 million to Multi-Shot, LLC, an NGP affiliated company, for services related to our drilling and completion activities.

Common Control Acquisitions

MEMP GP Acquisition. On June 1, 2016, as discussed in Note 1, the Partnership acquired all of the equity interests in our general partner, MEMP GP, from Memorial Resource for cash consideration of approximately $0.8 million. The acquisition was accounted for as an equity transaction and no gain or loss was recognized as a result of the acquisition. In connection with the closing of the transaction, our partnership agreement was amended and restated to, among other things, (i) convert MEMP GP’s 0.1% general partnership interest into a non-economic general partner interest, (ii) cancel the IDRs of the Partnership, and (iii) provide that the limited partners of the Partnership will elect the members of MEMP GP’s board of directors beginning with an annual meeting in 2017. On June 1, 2016, the Partnership also acquired the remaining 50% of the IDRs of the Partnership owned by an NGP affiliate.

February 2015 Acquisition. On February 23, 2015, as discussed in Note 1, we consummated the Property Swap. The Partnership recorded the following net assets (in thousands):

 

Related Party Agreements

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

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Omnibus Agreement

Memorial Resource provided management, administrative and operating services to the Partnership and our general partner pursuant to our omnibus agreement. Upon completion of the MEMP GP Acquisition, the omnibus agreement was terminated and the Partnership entered into a transition services agreement with Memorial Resource. See Note 12 for additional information related to the transition services agreement. The following table summarizes the amount of general and administrative expenses recognized under the omnibus agreement that are reflected in the accompanying statements of operations for the periods presented (in thousands):

 

Beta Management Agreement

Memorial Resource, through its wholly-owned subsidiary Beta Operating Company, LLC (“Beta Operating”), provided management and administrative oversight related to our offshore Southern California oil and gas properties in exchange for an annual management fee. Memorial Resource had the right to receive approximately $0.4 million from Rise Energy Beta, LLC annually. During the three and nine months ended September 30, 2015 we recognized $0.1 million and $0.3 million, respectively, under this agreement. This agreement was terminated in November 2015 in connection with the 2015 Beta Acquisition.

On June 1, 2016, Memorial Resource assigned and transferred Beta Operating to the Partnership in connection with the MEMP GP Acquisition.  

Classic Gas Gathering and Water Disposal Agreements

A discussion of these agreements is included in our 2015 Form 10-K. The amended gas gathering agreement was terminated in November 2015 in connection with a third party’s acquisition of Classic Pipeline and Gathering LLC’s (“Classic Pipeline”) Joaquin gathering system. Additionally, Classic Pipeline assigned its salt water system to OLLC in November 2015. For the three and nine months ended September 30, 2015, we incurred gathering and saltwater disposal fees of approximately $0.7 million and $2.7 million under these agreements.

 

 

Note 12. Commitments and Contingencies

Transition Services Agreement

On June 1, 2016 we closed the MEMP GP Acquisition. Upon closing of the MEMP GP Acquisition, we and Memorial Resource became unaffiliated entities. We terminated our omnibus agreement and entered into a transition services agreement with Memorial Resource to manage post-closing separation costs and activities. During the three and nine months ended September 30, 2016, we recorded $0.9 million and $1.4 million, respectively, of general and administrative expenses related to the transition services agreement with Memorial Resource.  

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, 2016, we had no environmental reserves recorded. As of December 31, 2015, we had approximately $0.2 million of environmental reserves recorded on our balance sheet. 

Supplemental Bond for Decommissioning Liabilities Trust Agreement

The trust account must maintain minimum balances as follows (in thousands):

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

In the event the account balance is less than the contractual amount, we must make additional payments. Interest income earned and deposited in the trust account mitigates the likelihood that additional payments will have to be made by us. As of September 30, 2016, the remaining obligation was approximately $2.7 million. In 2015, the BOEM issued a preliminary report that indicated the estimated costs of decommissioning may further increase, and we expect the amount to be finalized during the fourth quarter of 2016 after negotiations are completed.

The held-to-maturity investments held in the trust account as of September 30, 2016 for the U.S. Bank money market cash equivalent was $149.3 million.

 

 

Note 13. Subsequent Events

Amendment to Credit Facility and Borrowing Base Redetermination

For additional information, see Note 7.

Deferred Interest Payment and Limited Waiver and Twelfth Amendment to the Credit Agreement

For additional information, see Note 7.

Compensatory Arrangements of Certain Employees

On October 27, 2016, the Board of Directors (the “Board”) of MEMP GP, approved the adoption of a key employee incentive plan and a key employee retention program for the benefit of certain employees identified by the Board, including the named executive officers of the Partnership, whose continued employment and performance is critical to the success of MEMP GP and the Partnership. In adopting the plans, the Board relied upon the market analysis and advice of Pearl Meyers & Partners, LLC, the independent compensation consultant to the Partnership.

 

 

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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 consolidated and combined financial statements and accompanying notes in “Item 1. Financial Statements” contained herein and our 2015 Form 10-K filed with the SEC on February 24, 2016 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 a Delaware limited partnership formed in April 2011 to own, acquire and exploit oil and natural gas properties in North America. The Partnership is wholly-owned by its limited partners. Our general partner, which owns a non-economic general partner interest in us, is responsible for managing all of the Partnership’s operations and activities.

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our business activities are conducted through OLLC, our wholly-owned subsidiary, and its wholly-owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties and are principally located in Texas, Louisiana, Wyoming and offshore Southern California. Most of our oil and natural gas 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. As of December 31, 2015:

Recent Developments

Debt Instruments

Effective October 28, 2016, in connection with the semi-annual borrowing redetermination by the lenders under our revolving credit facility, the borrowing base under our revolving credit facility was reduced to $740.0 million and is scheduled to be further reduced to $720.0 million on December 1, 2016. In addition, we and our lenders reached an agreement on amending certain terms of our revolving credit facility. For information regarding the amendment to our revolving credit facility, see Note 7 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1.Financial Statements” of this quarterly report.  See “—Liquidity and Capital Resources” for additional information.  

In addition, we elected to defer an approximately $24.6 million interest payment due on November 1, 2016 with respect to the 7.625% senior notes due May 2021 (“2021 Senior Notes”). The interest payment is subject to a 30-day grace period under the indenture. After the grace period, the failure to pay interest would constitute a default and an event of default under our indentures. During the 30-day grace period, we expect to continue working with our noteholders regarding an effort to develop a comprehensive plan to de-lever the Partnership and strengthen our balance sheet. Failure to pay such interest payment on November 1, 2016 is a default and an event of default under our revolving credit facility. The lenders under the revolving credit facility, on November 1, 2016, waived such default and an event of default through November 30, 2016 subject to the terms and conditions set forth in the limited waiver and twelfth amendment. For more information regarding the waiver, see Note 7 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

Leadership Changes

In September 2016, John A. Weinzierl resigned as the Chief Executive Officer (“CEO”) of MEMP GP and William J. Scarff, who was serving as President of MEMP GP, was appointed to serve as CEO.

Mr. Weinzierl also resigned as Chairman of the Board, and Jonathan M. Clarkson, who was serving as an independent director on the board of directors of MEMP GP, was appointed to serve as Chairman of the Board. Mr. Weinzierl continues to serve as a director on the board of directors of MEMP GP.

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Divestitures

In July 2016, we closed a transaction to divest certain assets located in Colorado and Wyoming (the “Rockies Divestiture”) for total purchase price of approximately $16.9 million, including estimated post-closing adjustments. In June 2016, we closed a transaction to divest assets located in the Permian Basin (“Permian Divestiture”) for a total purchase price of approximately $36.9 million, including estimated post-closing adjustments. The proceeds from the divestitures were used to reduce borrowings under our revolving credit facility. See Note 3 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.

MEMP GP Acquisition

In June 2016, the Partnership acquired, among other things, all of the equity interests in MEMP GP from Memorial Resource for cash consideration of approximately $0.8 million. See Note 1 and Note 11 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.

Repurchase of Senior Notes

During the three months and nine months ended September 30, 2016, the Partnership repurchased an aggregate principal amount of approximately $1.5 million and $53.7 million, respectively, of the 2021 Senior Notes. During the nine months ended September 30, 2016, the Partnership repurchased an aggregate principal amount of approximately $32.0 million of the 6.875% senior notes due August 2022 (“2022 Senior Notes”). See Note 7 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.

Business Environment and Operational Focus

Our primary business objective is to generate stable cash flows, which would allow us to resume quarterly cash distributions to our unitholders. We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including: (i) production volumes; (ii) realized prices on the sale of our production; (iii) cash settlements on our commodity derivatives; (iv) lease operating expenses; (v) general and administrative expenses; and (vi) Adjusted EBITDA (defined below).

Principal Components of Cost Structure

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Memorial Resource provided management, administrative and operating services to the Partnership and our general partner pursuant to our omnibus agreement. Upon completion of the MEMP GP Acquisition, the omnibus agreement was terminated and the Partnership entered into a transition services agreement with Memorial Resource to manage certain post-closing separation costs and activities. See Note 11 and Note 12 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information. 

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our 2015 Form 10-K. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. These estimates, in our opinion, are subjective in nature, require the use 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.

 

 

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Results of Operations

The results of operations for the three and nine months ended September 30, 2016 and 2015 have been derived from our consolidated and combined financial statements.

The results of operations attributable to the previous owners may not necessarily be indicative of the actual results of operations that might have occurred if the Partnership had operated the applicable assets separately during those periods. The following table summarizes certain of the results of operations and period-to-period comparisons for the periods indicated (in thousands).

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Three Months Ended September 30, 2016 Compared to the Three Months Ended September 30, 2015

A net loss of $32.9 million was recorded during the three months ended September 30, 2016 compared to a net loss of $192.0 million recorded during the three months ended September 30, 2015.

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.

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Average outstanding borrowings under our revolving credit facility were $715.0 million during 2016 compared to $684.2 million during 2015. We had an average of $1.1 billion aggregate principal amount of our senior notes issued and outstanding during 2016 and an average of $1.2 billion aggregate principal amount of senior notes issued and outstanding during 2015.

Nine Months Ended September 30, 2016 Compared to the Nine Months Ended September 30, 2015

A net loss of $218.5 million was recorded during 2016 compared to a net loss of $468.5 million recorded during 2015.

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Average outstanding borrowings under our revolving credit facility were $765.7 million during 2016 compared to $607.1 million during 2015. We had an average of $1.2 billion aggregate principal amount of our senior notes issued and outstanding during both 2016 and 2015.

Liquidity and Capital Resources

Overview. Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements will depend on our ability to generate cash in the future. Our primary sources of liquidity and capital resources have historically been cash flows generated by operating activities, borrowings under our revolving credit facility and equity and debt capital markets.

Our revolving credit facility allows us to borrow in an amount up to the borrowing base, which 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. The lenders under our revolving credit facility have broad discretion to decrease our borrowing base.  Effective October 28, 2016, in connection with the semi-annual borrowing redetermination by the lenders under our revolving credit facility, the borrowing base was reduced to $740.0 million and is scheduled to be further reduced to $720.0 million on December 1, 2016. With our borrowing base at such levels, we will have limited to no available borrowing capacity and will likely be unable to remain in compliance with certain financial covenants under our revolving credit facility as early as the fourth quarter of 2016. As of October 28, 2016, we had approximately $714.0 million of outstanding borrowings under our revolving credit facility. In the case of a borrowing base deficiency, our revolving credit facility requires us to repay the deficiency, which we are permitted to do in equal monthly installments over a five-month period, or pledge additional oil and gas properties to eliminate such deficiency. If our borrowing base is redetermined below our current outstanding borrowings and we are unable to repay the deficiency or deposit additional collateral to eliminate such deficiency, there would be substantial doubt regarding our ability to continue as a going concern.

In addition, if we are unable to remain in compliance with the covenants under our revolving credit facility or the indentures governing our senior notes, or a cross-default occurs under either, absent relief from our lenders or noteholders, as applicable, we may be forced to repay or refinance such indebtedness and we may incur other damages. Upon the occurrence of an event of default, the lenders under our revolving credit facility or holders of our senior notes, as applicable, could elect to declare all amounts outstanding immediately due and payable or seek other remedies and the lenders could terminate all commitments to extend further credit under our revolving credit facility. If an event of default occurs under our revolving credit facility or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding or seek other remedies, we will not have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there would be substantial doubt regarding our ability to continue as a going concern. We might also be required to seek relief under the Bankruptcy Code.

In addition, we elected to defer an approximately $24.6 million interest payment due on November 1, 2016 with respect to the 2021 Senior Notes. The interest payment is subject to a 30-day grace period under the indenture. During the 30-day grace period, we expect to continue working with our debt holders regarding an effort to develop a comprehensive plan to de-lever the Partnership and strengthen our balance sheet. Failure to pay such interest payment on November 1, 2016 is a default and an event of default under our revolving credit facility. The lenders under the revolving credit facility, on November 1, 2016, waived such default and event of default through November 30, 2016 subject to the terms and conditions set forth in the limited waiver and twelfth amendment. Failure to make such interest payment on the 2021 Senior Notes prior to the expiration of the grace period on November 30, 2016 will result in a default and an event of default under the 2021 Senior Notes and an event of default under both our revolving credit facility and the indenture governing the 2022 Senior Notes. With respect to each of the 2021 Senior Notes and 2022 Senior Notes, if such an event of default continues, the trustee under the related indenture or the holders of at least 25% in aggregate principal amount of the then outstanding notes with respect to such series of notes may declare all the notes in such series to be due and payable immediately. Such an event of default would have a material adverse effect on our liquidity, financial condition and results of operations. For more information regarding the waiver, see Note 7 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

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As we have done throughout 2016, we expect to continue to focus on our liquidity and financial flexibility. We, along with our legal and financial advisors, are evaluating various options with the lenders under our revolving credit facility, and holders of our senior notes, that would improve our liquidity and strengthen our balance sheet, but there is no certainty that we will be able to implement any such options. We can provide no assurances that any refinancing or changes in our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all. Additionally, certain options may result in a wide range of outcomes for our stakeholders, including, for example, potential taxable cancellation of debt income (“CODI”), which would be directly allocated to our unitholders and reportable by the unitholders for U.S. federal income tax purposes. In addition to asset divestitures like the divestitures that have occurred earlier this year, we may engage in other transactions to de-lever the Partnership, such as terminating or restructuring commodity derivatives, debt exchanges, debt repurchases, refinancing arrangements, or other significant recapitalization transactions including seeking relief under the Bankruptcy Code.

Capital Markets. Our ability to obtain funding in the equity or capital markets has been, and will continue to be, constrained. We have filed a universal shelf registration statement with the SEC to register the offer and sale of our equity or debt securities to assist us in meeting our future working capital needs, capital expenditures, debt service and distributions to our partners. However, since we no longer qualify as a well-known seasoned issuer, we will need to file a post-effective amendment to the registration statement to convert it to a non-automatic shelf registration statement that we are eligible to use. Such post-effective amendment is subject to review by the SEC and must be declared effective by the SEC, which could delay our ability to raise debt or equity capital under the registration statement and may adversely affect our ability to access financing and the capital markets in a timely fashion. In May 2016, we also implemented our at-the-market program (the “ATM Program”), which allows us to issue our common units at prices and terms to be determined by market conditions and other factors. At September 30, 2016, approximately $57.6 million remained available for issuance under the ATM Program. There is no assurance that we can issue common units under this program on terms that are acceptable to us, or at all.

Hedging. Commodity hedging has been and remains an important part of our strategy to reduce cash flow volatility. Our hedging activities are intended to support oil, NGL, and natural gas prices at targeted levels and to manage our exposure to commodity price fluctuations. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved reserves over a three-to-six year period at any given point of time. We may, however, from time to time hedge more or less than this approximate range. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. The current market conditions may also impact our ability to enter into future commodity derivative contracts. During the nine months ended September 30, 2016, we terminated certain “in-the-money” crude oil and NGL derivatives settling in 2016 and certain crude oil basis swaps settling in 2016 and 2017. We received cash settlements of approximately $39.3 million from the termination of these crude oil and NGL derivatives. We used the proceeds from the settlements to repurchase senior notes. 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, 2016, see “Item 3 Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk.”

We evaluate counterparty risks related to our commodity derivative contracts and trade credit. Some of the lenders, or certain of their affiliates, under our revolving credit facility are counterparties to our derivative contracts. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices. We sell our oil and natural gas to a variety of purchasers. Non-performance by a customer could also result in losses.

Partnership Agreement. Our partnership agreement requires that we distribute all of our available cash (as defined in our partnership agreement) each quarter to our unitholders. In making cash distributions, our general partner attempts to avoid large variations in the amount we distribute from quarter to quarter. To facilitate this, our partnership agreement permits our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions to our unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to sustain our level of distributions. Our partnership agreement also permits our general partner to establish cash reserves for the proper conduct of the Partnership’s business (including reserves for future capital expenditures and for anticipated future credit needs of the Partnership) subsequent to any applicable quarter and to comply with applicable law or the Partnership’s debt instruments. Such cash reserves have the effect of reducing available cash and consequently, the distributions to our unitholders.  Covenants in our revolving credit facility may also restrict our distributions. See Note 8 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.

Capital Expenditures. For the nine months ended September 30, 2016, our total capital expenditures were approximately $48.5 million, which were primarily related to drilling, recompletions and capital workovers located in East Texas and Wyoming.

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Government Trust Account. In 2015, the Bureau of Safety and Environmental Enforcement (“BSEE”) issued a preliminary report that indicated the estimated cost of decommissioning the offshore production facilities associated with the Beta properties may increase. We are working with BOEM and certain prior third party owners to replace a portion of the funds maintained in the trust account pursuant to the government obligation with one or more surety bonds, which we believe would free up additional cash currently held in the trust account. At September 30, 2016, there was approximately $149.3 million in the trust account.

Working Capital. We expect to fund our working capital needs primarily with operating cash flows. We also plan to reinvest a sufficient amount of our operating cash flow to fund our expected capital expenditures. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements. See Note 1 and Note 7 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements,” “— Recent Developments — Debt Instruments,” “— Overview” and “Part II — Other Information — Item 1A. Risk Factors” of this quarterly report for additional information.

As of September 30, 2016, we had a working capital balance of $122.8 million primarily due to a net asset balance of $152.7 million of current derivative instruments partially offset by the timing of accruals, which included accrued capital expenditures of approximately $7.6 million, accrued lease operating expense of approximately $12.4 million and accrued interest payable of approximately $26.1 million.

Debt Agreements

Revolving Credit Facility. OLLC is a party to a $2.0 billion revolving credit facility that matures in March 2018 and is guaranteed by us and all of our current and future subsidiaries (other than certain immaterial subsidiaries). As of September 30, 2016, we had $714.0 million of outstanding borrowings and $2.4 million of outstanding letters of credit. The borrowing base is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil, natural gas and NGL reserves, which will take into account the prevailing oil, natural gas and NGL prices at such time, as adjusted for the impact of commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. As of September 30, 2016, we believe we were in compliance with all of the financial and other covenants under our revolving credit facility. For additional information regarding our revolving credit facility, see Note 7 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

Senior Notes. As of September 30, 2016, there was approximately $646.3 million aggregate principal amount of the 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 our 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 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 a base indenture and supplements thereto. During the nine months ended September 30, 2016, we repurchased an aggregate principal amount of approximately $53.7 million of the 2021 Senior Notes at a weighted average price of 49.09% of the face value of the 2021 Senior Notes. See Note 7 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements,” and “– Recent Developments – Debt Instruments” of this quarterly report for additional information.

As of September 30, 2016, there was approximately $465.0 million aggregate principal amount of the 2022 Senior Notes outstanding. The 2022 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of our 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 a base indenture and supplements thereto. During the nine months ended September 30, 2016, we repurchased an aggregate principal amount of approximately $32.0 million of the 2022 Senior Notes at a weighted average price of 46.50% of the face value of the 2022 Senior Notes. See Note 7 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the nine months ended September 30, 2016 and 2015 have been derived from both our consolidated financial statements and the previous owners’ combined financial statements. The combined financial statements of the previous owner reflect the common control acquisition from Memorial Resource in February 2015. 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. Financial Statements” of this quarterly report.

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Nine Months Ended September 30, 2016 Compared to the Nine Months Ended September 30, 2015

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities increased by $13.6 million period-over-period. Production decreased 5.8 Bcfe (approximately 8%) and average realized sales price decreased $0.81 per Mcfe. During 2016, oil, natural gas and NGL revenues were $202.6 million, a decrease of $74.1 million compared to 2015. Lease operating expenses were $96.6 million, a decrease of $34.2 million compared to 2015. Taxes other than income decreased to $11.4 million in 2016 from $19.6 million during 2015. Cash paid for interest during 2016 was $80.4 million compared to $75.4 million during 2015. Cash settlements on terminated derivatives were $39.3 million during 2016 compared to $27.1 million during 2015 and we paid $27.1 million in premiums for commodity derivatives in 2015. Cash settlements received on expired commodity derivatives were $183.2 million during 2016 compared to $175.7 million during 2015.

Investing Activities. Net cash used in investing activities during 2016 was $9.1 million, of which $50.5 million was used for additions to oil and natural gas properties and $7.6 million was used for additions to other property and equipment. These amounts were partially offset by $54.7 million in proceeds from the sale of oil and natural gas properties primarily related to the Permian Divestiture and Rockies Divestiture. 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 third parties and $196.1 million was used for additions to oil and natural gas properties. We also received a post-closing settlement receipt of $9.6 million related to an acquisition of Wyoming properties during 2015. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our offshore Southern California oil and natural gas properties. Additions to restricted investments were $5.6 million during 2016 compared to $3.9 million during 2015.

Financing Activities. Distributions to partners during 2016 were $13.3 million compared to $138.3 million during 2015. The decrease is primarily due to a decrease in the declared distribution rate. During 2015, we paid $78.4 million to Memorial Resource in connection with a common control acquisition transaction. Capital contributions received from the previous owners were $1.9 million during 2015.

The Partnership had net repayments of $122.0 million under its revolving credit facility during 2016. The Partnership had net borrowings of $284.0 million under its revolving credit facility during 2015 that were primarily used to fund a common control acquisition transaction and to fund its drilling program. For additional information regarding the common control acquisition, see Note 11 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

During 2016, we repurchased an aggregate principal amount of approximately $85.7 million of the 2021 Senior Notes and 2022 Senior Notes for $41.3 million. During 2015, we repurchased an aggregate principal amount of approximately $3.0 million of the 2022 Senior Notes of which $2.9 million was classified as financing outflow representing repayment of the original proceeds and $0.3 million classified as an operating inflow.

During 2016, we sold 1,178,102 common units under the ATM Program and generated net proceeds of $2.1 million. During 2015, we repurchased $54.2 million in common units, which represented a repurchase and retirement of 3,641,721 common units under the December 2014 repurchase program. This repurchase program expired in December 2015. See Note 8 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 our 2016 and 2015 repurchases.

Adjusted EBITDA

We include in this report the non-GAAP financial measure Adjusted EBITDA and provide our reconciliation of Adjusted EBITDA to net income and net cash flows from operating activities, our most directly comparable financial measures calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income (loss):

Plus:

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Less:

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, research analysts and rating agencies, to assess:

In addition, management uses Adjusted EBITDA to evaluate actual cash flow available to pay distributions to our unitholders, develop existing reserves or acquire additional oil and natural gas properties.

Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

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The following tables present our reconciliation of Adjusted EBITDA to net income and net cash flows from operating activities, our most directly comparable GAAP financial measures, for each of the periods indicated.

Reconciliation of Adjusted EBITDA to Net Income (Loss)

Reconciliation of Adjusted EBITDA to Net Cash from Operating Activities

Contractual Obligations

During the nine months ended September 30, 2016, there were no significant changes in our consolidated contractual obligations from those reported in our 2015 Form 10-K filed with the SEC on February 24, 2016 except for indebtedness. Total indebtedness was approximately $1.8 billion at September 30, 2016 compared to $2.0 billion at December 31, 2015. See Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.

Off–Balance Sheet Arrangements

As of September 30, 2016, we had no off–balance sheet arrangements.

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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 for additional information.

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 Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” included in our 2015 Form 10-K.

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our oil, natural gas, 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. It has been our practice to generally enter into costless collars and fixed price swaps only with lenders under our credit agreement. During the nine months ended September 30, 2016, we terminated certain “in-the-money” crude oil and NGL derivatives settling in 2016 and certain crude oil basis swaps settling in 2016 and 2017. We received cash settlements of approximately $39.3 million from the termination of these crude oil and NGL derivatives and utilized the proceeds to buy back senior notes.

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, 2016, see Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included “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, 2016.

The fair value of our senior notes are sensitive to changes in interest rates. We estimate the fair value of the 2021 Senior Notes and 2022 Senior Notes using quoted market prices. The carrying value (net of debt issuance costs and any discount or premium) is compared to the estimated fair value in the table below (in thousands):

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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. Some of the lenders, or certain of their affiliates, under our credit agreement 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. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. These agreements allow us to offset our asset position with our liability position in the event of default by the counterparty. 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, 2016, after taking into effect netting arrangements, we had counterparty exposure of $188.7 million related to our derivative instruments. As a result, had all counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $267.0 million against amounts outstanding under our revolving credit facility at September 30, 2016.

Evaluation of Disclosure Controls and Procedures

As required by Rules 13a-15(b) and 15d-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 the principal executive officer and principal financial officer of our general partner, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) and under the Exchange Act) as of the end of the period covered by this quarterly report. 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 the principal executive officer and principal financial officer of our general partner, 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 the evaluation, the principal executive officer and principal financial officer of our general partner have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of September 30, 2016.

Change in Internal Controls Over Financial Reporting

No changes in our internal control over financial reporting occurred during the quarter ended September 30, 2016 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 12, “Commitments and Contingencies — Litigation & Environmental,” of the Notes to Unaudited Condensed Consolidated Financial Statements included in this quarterly report, which is incorporated herein by reference.

Our business faces many risks. Any of the risks discussed elsewhere in this quarterly report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. Except for the risk factors described below, there have been no material changes with respect to the risk factors since those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015 filed with the SEC on February 24, 2016 and our Current Report on Form 8-K filed with the SEC on May 25, 2016.

Our lenders periodically redetermine the amount we may borrow under our revolving credit facility, which may materially impact our operations.

Our revolving credit facility allows us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base is subject to redetermination on at least a semi-annual basis primarily based on an engineering report with respect to our estimated natural gas, oil and NGL reserves, which takes into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts.  Accordingly, declining commodity prices may have an impact on the amount we can borrow under our revolving credit facility, which could affect our cash flows and ability to execute on our business plans. Any reduction in our borrowing base would materially and adversely our business and financing activities, limit our flexibility and management’s discretion in operating our business, and increase the risk that we may default on our debt obligations.  In addition, as hedges roll off, our borrowing base is subject to further reduction. Our borrowing base was reduced to $740.0 million effective October 28, 2016 in connection with the semi-annual borrowing redetermination by the lenders under our revolving credit facility and will automatically be further reduced to $720.0 million on December 1, 2016.  Our revolving credit facility requires us to repay any deficiency, which we are permitted to do in equal monthly installments over a five-month period, or pledge additional oil and gas properties to eliminate such deficiency, which we are required to do within 30 days of electing to do so. If our outstanding borrowings exceed the borrowing base and we are unable to repay the deficiency or pledge additional oil and gas properties to eliminate such deficiency, our failure to repay any of the installments due related to the borrowing base deficiency would constitute an event of default under our revolving credit facility and as such, the lenders could declare all outstanding principal and interest to be due and payable, could freeze our accounts, or foreclose against the assets securing the obligations owed under our revolving credit facility, and we could be forced into bankruptcy or liquidation. In addition, a payment default under our revolving credit facility would result in an event of default under our 2021 Senior Notes and 2022 Senior Notes. In such case, we may not have sufficient assets to repay our creditors, including the holders of our Senior Notes. As a result, there may not be any value remaining attributable to the holders of our common units.

We are currently considering, and may be required to make, significant changes to our capital structure to maintain sufficient liquidity and manage and strengthen our balance sheet.  

Our primary liquidity requirements, in addition to normal operating expenses, are for servicing our debt, capital expenditures and distributions to our limited partners. We have historically funded our operations, acquisitions and cash distributions primarily through cash generated from operations, amounts available under our revolving credit facility and equity and debt offerings. Our future cash flows are subject to a number of variables, including oil and natural gas prices, and due to the steep decline in commodity prices, our ability to obtain funding in the equity or capital markets has been, and will continue to be, constrained, and there can be no assurances that our liquidity requirements will continue to be satisfied given current commodity prices.  Effective October 28, 2016, in connection with the semi-annual borrowing redetermination by the lenders under our revolving credit facility, the borrowing base was reduced to $740.0 million and will automatically be further reduced to $720.0 million on December 1, 2016. With our borrowing base at such levels, we will have limited to no available borrowing capacity and will likely be unable to remain in compliance with certain financial covenants under our revolving credit facility as early as the fourth quarter of 2016. If our sources of liquidity are not sufficient to fund our current or future liquidity needs, including as a result of a decrease in the borrowing base under our revolving credit facility, we may be required to take other actions, including those actions discussed below.

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The long-term downturn in commodity prices has had a detrimental impact on our financial position and is forecasted to continue. We continually monitor the capital markets and our capital structure and may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening our balance sheet, meeting our debt service obligations and/or achieving cost efficiency. For example, we could pursue options such as refinancing, restructuring or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity concerns and high debt levels. We are evaluating various options with the lenders under our revolving credit facility, and holders of the 2021 Senior Notes and the holders of the 2022 Senior Notes, but there is no certainty that we will be able to implement any such options, and we can provide no assurances that any refinancing or changes in our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all.  Additionally, certain options may result in a wide range of outcomes for our stakeholders, including, for example, potential taxable CODI, which would be directly allocated to our unitholders and reportable by the unitholders for U.S. federal income tax purposes.

We can provide no assurances that any of these efforts will be successful or will result in additional liquidity. It is also possible additional adjustments to our plan and outlook may occur based on market conditions and our needs at that time, which could include: selling assets; reducing or delaying capital investments; seeking to raise additional capital; liquidating all or a portion of our hedge portfolio; seeking additional partners to develop our assets; reducing our planned capital program; continuing to take, and potentially increasing, our cost saving measures to reduce costs, including renegotiation contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs; or revising or delaying our other strategic plans.

Any Partnership de-levering transaction or change in the Partnership capital structure may involve significant taxable cancellation of debt income, such that the Partnership’s unitholders may be required to pay taxes on their share of such income even if they do not receive any cash distributions from the Partnership.

The Partnership’s unitholders, as the owners of the Partnership, are allocated the taxable income (or loss) of the Partnership for income tax purposes.  Each unitholder is required to report its share of the Partnership’s taxable income on its federal and applicable state and local income tax returns. Accordingly, depending on their individual tax position, each unitholder may be required to pay income taxes on its share of the Partnership’s taxable income, even if the unitholder receives no cash distributions from the Partnership, which could happen.

In response to current market conditions, the Partnership may engage in transactions to de-lever the Partnership and manage its liquidity that could result in the allocation of taxable income to the Partnership’s unitholders without a corresponding cash distribution and possibly without any cash distribution. For example, the Partnership may sell assets and use the proceeds to repay existing debt, in which case unitholders would be allocated any taxable income or gain resulting from the sale. Further, the Partnership may pursue other opportunities to reduce its existing debt, such as exchanges, repurchases, modifications or extinguishment of Partnership debt that could result in CODI being allocated to the Partnership’s unitholders as ordinary taxable income. It is possible that the income tax liability resulting from the allocation of such CODI, if any, to a unitholder could exceed the current value of the unitholder’s investment in the Partnership. The ultimate effect of an allocation of CODI to a unitholder will depend on the unitholder’s individual tax position, including, for example, the availability of any current or prior-year “suspended” passive losses to offset all or a portion of the allocable CODI.

We cannot provide any assurance that any of the various options that we, along with our legal and financial advisors, are evaluating to mitigate any potential allocation of taxable CODI to unitholders upon a de-levering transaction or other change in the Partnership capital structure will be achieved or will be optimal for unitholders. Unitholders are encouraged to consult their tax advisors with respect to the consequences to them of CODI.

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The following table summarizes our repurchase activity during the quarterly period ended September 30, 2016:

 

None.

Not applicable.

None.

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

 

 

 

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SIGNATURES

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

 

 

 

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EXHIBIT INDEX

 

48

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