ITEM 1.
BUSINESS
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 owned 99.9% by its limited partners and 0.1% by its general partner, which is a wholly-owned subsidiary of Memorial Resource. Our general partner 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 located in Texas, Louisiana, Colorado, 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:
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Our total estimated proved reserves were approximately 1,268 Bcfe, of which approximately 43% were oil and 63% were classified as proved developed reserves;
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We produced from 3,357 gross (1,960 net) producing wells across our properties, with an average working interest of 58%, and the Partnership or Memorial Resource is the operator of record of the properties containing 95% of our total estimated proved reserves; and
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Our average net production for the three months ended December 31, 2015 was 257.3 MMcfe/d, implying a reserve-to-production ratio of approximately 14 years.
2015 Developments
2015 Beta Acquisition
In November 2015, we purchased the noncontrolling interest in San Pedro Bay Pipeline Company (“SPBPC”) for approximately $6.0 million and completed an acquisition of the remaining interests in our oil and gas properties offshore Southern California (the “Beta properties”) from a third party for approximately $94.6 million (the “2015 Beta Acquisition”).
We first acquired our interests in the Beta properties in December 2012. The 2015 Beta Acquisition consisted of the 48.25% remaining working interests in three Pacific Outer Continental Shelf blocks in the Beta Field that are located in federal waters approximately eleven miles offshore the Port of Long Beach, California and the 48.25% remaining interest in associated facilities including (i) two combined production and drilling platforms (ii) one production processing platform, (iii) a 17.5 mile long 16-inch diameter oil pipeline and (iv) an onshore pump station, tankage and metering facility.
Semi-Annual Borrowing Base Redetermination
In November 2015, in connection with the semi-annual borrowing base redetermination by lenders under the Partnership’s revolving credit facility, the borrowing base under the revolving credit facility decreased from $1.30 billion to approximately $1.175 billion. The new borrowing base became effective on November 4, 2015. The borrowing base reduction was primarily the result of the deterioration of commodity prices in the oil and natural gas industry. We anticipate the next redetermination will become effective in April 2016.
2015 Common Control Acquisition
In February 2015, we and Memorial Resource completed a transaction in which we exchanged our oil and gas properties in North Louisiana and approximately $78.4 million in cash for Memorial Resource’s East Texas and Louisiana oil and gas properties (the “Property Swap”). Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee, which is comprised entirely of independent directors.
Conversion of Subordinated Units
In February 2015, the subordination period for the 5,360,912 subordinated units ended. All of the subordinated units, which were owned by MRD Holdco, converted to common units on a one-to-one basis at the end of the subordination period. MRD Holdco sold all of the common units during the three months ended June 30, 2015 and no longer owns any of our outstanding common units.
MEMP Repurchase Program
In December 2014, the board of directors of our general partner authorized the repurchase of up to $150.0 million of our common units (“MEMP Repurchase Program”). During 2015, we repurchased $52.8 million in common units, which represents a repurchase and retirement of 3,547,921 common units under the MEMP Repurchase Program. The MEMP Repurchase Program expired in December 2015.
Properties
We engaged Ryder Scott Company, L.P. (“Ryder Scott”), our independent reserve engineers, to audit our reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2015. The following table summarizes information, based on a reserve report prepared by our internal reserve engineers and audited by Ryder Scott (which we refer to as our “reserve report”), about our proved oil and natural gas reserves by geographic region as of December 31, 2015 and our average net production for the three months ended December 31, 2015:
(1)
Determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
(2)
Standardized measure is calculated in accordance with Accounting Standards Codification, or ASC, Topic 932, Extractive Activities-Oil and Gas, and is calculated using SEC pricing, before market differentials, of $46.79/Bbl for crude oil and $2.58/MMBtu for natural gas. 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 commodity derivative contracts.
(3)
The average reserve-to-production ratio is calculated by dividing estimated net proved reserves as of December 31, 2015 by the annualized average net production for the three months ended December 31, 2015.
Hedging Strategies
We maintain a portfolio of commodity derivative contracts that covers our estimated production from total proved reserves over a three-to-six year period at any given point in time. Historically, we have used crude oil, natural gas and NGL financial swaps, collar contracts and commodity basis financial swaps. Our current hedging portfolio covers the following levels of our expected production through 2019:
Business Strategies
Our primary business objective is to generate stable cash flows that will allow us to deliver sustainable quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions as market conditions dictate. To achieve our objective, we intend to execute the following business strategies:
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Maintain a capital structure that provides financial flexibility to opportunistically finance our development and acquisition strategy.
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Reduce exposure to commodity price risk and stabilize cash flows through a disciplined commodity hedging policy.
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Exploit opportunities on our current properties and manage our operating costs and capital expenditures.
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Maintain and grow a stable production profile through accretive acquisitions and lower-risk development.
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Leverage our relationships with Memorial Resource, the Funds, and their respective affiliates (including NGP) to gain access to acquisitions of producing oil and natural gas properties that meet our acquisition criteria.
Our Principal Business Relationships
Our Relationship with Memorial Resource
Memorial Resource is a publicly traded Delaware corporation focused on the exploration, development and acquisition of natural gas and oil properties. Memorial Resource is engaged in its business with the objective of growing its reserves, production and cash flows.
Memorial Resource owns all of the voting interests in our general partner, which owns 50% of our incentive distribution rights. Our general partner is party to an omnibus agreement with a wholly owned subsidiary of Memorial Resource and the Partnership in which Memorial Resource has agreed to provide the administrative, management and operational services that we believe are necessary to allow our general partner to manage, operate and grow our business.
Our Relationship with Natural Gas Partners and the Funds
Founded in 1988, Natural Gas Partners is a family of private equity investment funds, with approximately $16.5 billion of cumulative equity commitments, organized to make investments in the natural resources sector. NGP is part of the investment platform of NGP Energy Capital Management, a premier investment franchise in the Natural Resources industry.
The Funds, which are three of the private equity funds managed by NGP, collectively control MRD Holdco, which together with a group controls Memorial Resource. The Funds collectively indirectly own 50% of our incentive distribution rights. The remaining 50% of our incentive distribution rights is owned by our general partner, which is owned by Memorial Resource.
The employees of NGP are experienced energy professionals with substantial expertise in investing in the oil and natural gas business. In connection with NGP’s business, these employees review a large number of potential acquisitions and are involved in decisions relating to the acquisition and disposition of oil and natural gas assets by the various portfolio companies in which NGP owns interests. We believe that our relationship with NGP, and its experience investing in oil and natural gas companies, provides us with a number of benefits, including increased exposure to acquisition opportunities and access to a significant group of transactional and financial professionals who have experience in assisting the companies in which it has invested to meet their financial and strategic growth objectives. We believe we benefit from the collective expertise of NGP’s employees and their extensive network of industry relationships, and accordingly, the access to potential acquisition opportunities that might not otherwise be available to us. Although we may have the opportunity to make acquisitions as a result of our relationship with NGP and the Funds, neither NGP nor the Funds has any legal obligation to offer to us (or inform us about) any acquisition opportunities, may decide not to offer any acquisition opportunities to us and is not restricted from competing with us, and we cannot say which, if any, of such potential acquisition opportunities we would choose to pursue.
Our Areas of Operation
East Texas/Louisiana
Approximately 42% of our estimated proved reserves as of December 31, 2015 and approximately 61% of our average daily net production for the three months ended December 31, 2015 were located in the East Texas/Louisiana region. Those properties include wells and properties primarily located in the Joaquin, Carthage, Willow Springs, and East Henderson fields in East Texas. Those properties collectively contained 535 Bcfe of estimated net proved reserves as of December 31, 2015 based on our reserve report and generated average net production of 156.0 MMcfe/d for the three months ended December 31, 2015. For information regarding the Property Swap, see “-2015 Developments-2015 Common Control Acquisition” contained herein.
Rockies
Approximately 39% of our estimated proved reserves as of December 31, 2015 and approximately 17% of our average daily net production for the three months ended December 31, 2015 were located in the Rockies region. Our Rockies properties are primarily located in Colorado and Wyoming. Key fields include the Lost Soldier and Wertz fields in Wyoming at our Bairoil complex. Our Rockies properties contained 78.0 MMBbls and 21.7 Bcf of estimated net proved reserves of oil and NGLs combined and natural gas, respectively, as of December 31, 2015 based on our reserve report and generated average net production of 43.8 MMcfe/d for the three months ended December 31, 2015.
Based on our reserve report, the Lost Soldier field contains more than 15% of our total estimated reserves. The oil properties in this field were acquired in July 2014. The following table summarizes production volumes from this field from the date of acquisition through December 31, 2015:
Offshore Southern California
Approximately 11% of our estimated proved reserves as of December 31, 2015 and approximately 7% of our average daily net production for the three months ended December 31, 2015 were located offshore Southern California. These properties, the Beta properties, consist of: all of the working interests and a 75.19% average net revenue interest in three Pacific Outer Continental Shelf blocks (P-0300, P-0301 and P-0306), referred to as the Beta unit, in the Beta Field located in federal waters approximately 11 miles offshore the Port of Long Beach, California. Our Beta properties contained 22.7 MMBbls of estimated net proved oil reserves as of December 31, 2015 based on our reserve report. Subsequent to the 2015 Beta Acquisition, the Beta properties collectively generated average net production of 3,864 Bbls/d of oil from the time of acquisition through December 31, 2015.
The Beta properties also include two wellbore production platforms, referred to as the Ellen and Eureka platforms, with permanent drilling equipment systems, one production handling and processing platform, referred to as the Elly platform, the San Pedro Bay Pipeline Company, which owns and operates a 16-inch diameter oil pipeline that extends approximately 17.5 miles from the Elly platform to the Beta pump station located onshore at the Port of Long Beach, California, and an onshore tankage and metering facility.
South Texas
Approximately 7% of our estimated proved reserves as of December 31, 2015 and approximately 11% of our average daily net production for the three months ended December 31, 2015 were located in the South Texas region. Our South Texas properties include wells and properties in numerous fields located primarily in the Eagle Ford, Eagleville, NE Thompsonville, Laredo and East Seven Sisters fields. Our South Texas properties contained 88 Bcfe of estimated net proved reserves as of December 31, 2015 based on our reserve report. Those properties collectively generated average net production of 28.3 MMcfe/d for the three months ended December 31, 2015.
Permian Basin
Approximately 1% of our estimated proved reserves as of December 31, 2015 and approximately 4% of our average daily net production for the three months ended December 31, 2015 were located in the Permian Basin region of West Texas. Our Permian Basin properties include wells primarily in the Anita, Bronte, Dimmitt, Elkhorn, Hendrick and Kingdom Abo fields. Our Permian Basin properties contained 3.0 MMBbls and 0.2 Bcf of estimated net proved reserves of oil and natural gas, respectively, as of December 31, 2015 based on our reserve report and generated average net production of 9.7 MMcfe/d for the three months ended December 31, 2015.
Our Oil and Natural Gas Data
Our Reserves
Internal Controls. Our proved reserves were estimated at the well or unit level and audited for reporting purposes by Ryder Scott, our independent reserve engineers. Memorial Resource maintains internal evaluations of our reserves in a secure reserve engineering database. Ryder Scott interacts with Memorial Resource’s internal petroleum engineers and geoscience professionals in each of our operating areas and with operating, accounting and marketing employees to obtain the necessary data for the reserves audit process. Reserves are reviewed and approved internally by our senior management on a semi-annual basis and evaluated by our lender group on at least a semi-annual basis in connection with borrowing base redeterminations under our revolving credit facility. Our reserve estimates are audited by Ryder Scott at least annually.
Our internal professional staff works closely with Ryder Scott to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve audit process. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, we provide Ryder Scott other pertinent data, such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make all requested information, as well as our pertinent personnel, available to the external engineers as part of their audit of our reserves.
Qualifications of Responsible Technical Persons
Internal Engineers. Christa Yin is the technical person at Memorial Resource primarily responsible for overseeing the preparation of the reserves estimates and liasoning with and providing oversight of our third-party reserve engineers, which audited the internally prepared reserve report for our properties. Ms. Yin has been practicing petroleum engineering at Memorial Resource since March 2015 and has over 18 years of experience in the estimation and evaluation of reserves. From March 2014 to March 2015, she was employed by Tundra Oil and Gas, where she was responsible for analysis of acquisitions, generating development plans, and managing reserves. From August 2011 to March 2014, she worked for HighMount Exploration & Production LLC as Manager of Acquisitions and Divestitures. From February 2005 to August 2011, Ms. Yin was employed by Tecpetrol, where she was responsible for generating development plans and managing and evaluating the reserves for the Gulf Coast region. From November 2003 to February 2005, Ms. Yin was employed by Marathon Oil Company where she was responsible for evaluating reserves and field development of various fields in Oklahoma. From June 1997 to November 2003, she held various positions which included the evaluation and estimation of reserves at Coastal Oil & Gas, which subsequently merged with El Paso Production Company. Ms. Yin is a graduate of Texas A&M University with a B.S. in petroleum engineering.
Ryder Scott Company, L.P. Ryder Scott is an independent oil and natural gas consulting firm. No director, officer, or key employee of Ryder Scott has any financial ownership in us, the Funds, or any of their respective affiliates. Ryder Scott’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported. Ryder Scott has not performed other work for us, the Funds, or any of their respective affiliates that would affect its objectivity. The audit of estimates of our proved reserves presented in the Ryder Scott reserve report were overseen by Timothy Wayne Smith.
Mr. Smith has been practicing consulting petroleum engineering at Ryder Scott since 2008. Before joining Ryder Scott, Mr. Smith served in a number of engineering positions with Wintershall Energy and Cities Service Oil Company. Mr. Smith is a Licensed Professional Engineer in the State of Texas with over 24 years of practical experience in the estimation and evaluation of petroleum reserves. He graduated from West Virginia University with a B.S. in petroleum engineering and from University of Phoenix with an M.B.A.
Mr. Smith meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
Estimated Proved Reserves
The following table presents the estimated net proved oil and natural gas reserves attributable to our properties and the standardized measure amounts associated with the estimated proved reserves attributable to our properties as of December 31, 2015, based on our internally prepared reserve report audited by Ryder Scott, our independent reserve engineers. The standardized measure amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.
(1)
Determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
(2)
Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest expense, or to depletion, depreciation and amortization. The future cash flows are discounted using an annual discount rate of 10%. 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. For a description of our commodity derivative contracts, please read “Item 1. Business-Operations-Derivative Activities” as well as “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Commodity Derivative Contracts.”
(3)
Our estimated net proved reserves and related standardized measure were determined using 12-month trailing average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month in effect as of the date of the estimate, without giving effect to derivative contracts, held constant throughout the life of the properties. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
The data in the table above represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. For a discussion of risks associated with internal reserve estimates, please read “Item 1A.
ITEM 1A.
RISK FACTORS
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a business similar to ours. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we may not be able to pay distributions on our common units, the trading price of our common units could decline and our unitholders could lose all or part of their investment. Other risks are also described in “Item 1. Business” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
Risks Related to Our Business
We may not have sufficient cash to pay distributions on our common units at the current distribution level or at all.
We may not have sufficient available cash each quarter to pay our current quarterly distribution or any other amount. Under the terms of our partnership agreement, the amount of cash available for distribution will be reduced by our operating expenses and the amount of any cash reserves established by our general partner to provide for future operations, future capital expenditures, including acquisitions of additional oil and natural gas properties, future debt service requirements and future cash distributions to our unitholders.
The amount of cash we distribute on our units principally depends on the cash we generate from operations, which depends on, among other things:
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the amount of oil, natural gas and NGLs we produce;
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the prices at which we sell our oil, natural gas and NGL production;
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the amount and timing of settlements of our commodity derivatives;
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the level of our operating costs, including maintenance capital expenditures and payments to our general partner and its affiliates; and
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the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon.
If we do not achieve our expected operational results, as a result of reduced capital expenditures, reduced liquidity or otherwise, distributions on our common units may decrease or be eliminated. Any such decrease or elimination in distributions may cause the market price of our common units to decline substantially.
For a description of additional restrictions and factors that may affect our ability to make cash distributions to our unitholders, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
The terms of our indebtedness include restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.
The operating and financial restrictions and covenants in our revolving credit facility, the indentures governing our senior notes and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions to our unitholders. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources.” Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our revolving credit facility that are not cured or waived within the appropriate time periods provided in our revolving credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions to our unitholders will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our revolving credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our revolving credit facility, the lenders could seek to foreclose on our assets.
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. The next borrowing base redetermination is expected to become effective in April 2016 and that redetermination will likely result in the lowering of our borrowing base. Any redeterminations thereafter could result in the lowering of our borrowing base further and, in such case, we would likely be required to repay any indebtedness outstanding in excess of the borrowing base. In connection with any such redetermination in the current environment, we may also be required to amend our revolving credit facility, which amendment could include additional restrictions and covenants that would further restrict 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 could be subject to further reduction. If we are unable to repay any borrowings in excess of a decreased borrowing base, we would be in default and, among other things, no longer able to make any distributions to our unitholders.
The terms and conditions governing our indebtedness, including our senior notes and our revolving credit facility:
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require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate;
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increase our vulnerability to economic downturns and adverse developments in our business;
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limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;
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place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;
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place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness;
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make it more difficult for us to satisfy our obligations under our senior notes or other debt and increase the risk that we may default on our debt obligations; and
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limit management’s discretion in operating our business.
We may not be able to generate enough cash flow to meet our debt obligations and may be forced to take other actions to satisfy our debt obligations that may not be successful.
We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can service in some periods may not be appropriate for us in other periods. Moreover, and subject to certain limitations, we may be able to incur substantial additional indebtedness in the future. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.
If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:
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refinancing or restructuring our debt;
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selling assets;
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reducing or delaying capital investments; or
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seeking to raise additional capital.
However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing, could materially and adversely affect our ability to make payments on our indebtedness and our business, financial condition, results of operations and cash available for distribution.
Furthermore, our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments, including our revolving credit facility, may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our debt instruments restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.
We distribute all of our available cash to our unitholders after reserves established by our general partner, which may limit the cash available to service our indebtedness or otherwise operate our business.
Subject to the limitations on restricted payments contained in the indentures governing our senior notes and in our revolving credit facility, we will distribute all of our “available cash” each quarter to our unitholders. “Available cash” is defined in our partnership agreement.
As a result, we may not accumulate significant amounts of cash. These distributions could significantly reduce the cash available to us in subsequent periods to make payments on our indebtedness or otherwise operate our business.
We no longer qualify as a “well-known seasoned issuer,” which limits our ability to access the capital markets in a timely fashion.
The filing of this annual report will render us unable to use our currently effective universal shelf Form S-3 registration statement as, on the date of filing of this annual report, we no longer meet the criteria of a “well-known seasoned issuer” under which the Form S-3 registration statement was originally filed as an automatic shelf registration statement. If we wish to continue to use such registration statement to issue securities from time to time, 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 adversely affect our ability to access financing and the capital markets in a timely fashion.
Despite our current level of indebtedness, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial indebtedness.
We and our subsidiaries may be able to incur substantial additional indebtedness in the future, subject to certain limitations, including under our revolving credit facility and under the indentures for our senior notes. If new debt is added to our current debt levels, the related risks that we now face could increase. Our level of indebtedness could, for instance, prevent us from engaging in transactions that might otherwise be beneficial to us or from making desirable capital expenditures. This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations. In addition, the incurrence of additional indebtedness could make it more difficult to satisfy our existing financial obligations.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk - Interest Price Risk” included under Part II of this annual report for further information regarding interest rate sensitivity.
We may incur additional debt to enable us to pay our quarterly distributions.
We may be unable to pay our current quarterly distribution without borrowing under our revolving credit facility or otherwise. If we use borrowings to pay distributions to our unitholders for an extended period of time rather than to fund capital expenditures and other activities relating to our operations, we may be unable to maintain or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness incurred to pay these distributions, will reduce our cash available for distribution on our units and will have a material adverse effect on our business, financial condition and results of operations. If we borrow to pay distributions to our unitholders during periods of low commodity prices and commodity prices remain low, we may have to further reduce our distribution to our unitholders to avoid excessive leverage.
Oil, natural gas and NGL prices are volatile, due to factors beyond our control, and greatly affect our business, results of operations and financial condition. Any decline in, or sustained low levels of, oil, natural gas and NGL prices will cause a decline in our cash flow from operations, which could materially and adversely affect our business, results of operations and financial condition and could cause us to reduce our distributions or cease paying distributions altogether.
Our revenues, operating results, profitability, liquidity, future growth and the value of our assets depend primarily on prevailing commodity prices. Historically, oil and natural gas prices have been volatile and fluctuate in response to changes in supply and demand, market uncertainty, and other factors that are beyond our control, including:
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the regional, domestic and foreign supply of oil, natural gas and NGLs;
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the level of commodity prices and expectations about future commodity prices;
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the level of global oil and natural gas exploration and production;
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localized supply and demand fundamentals, including the proximity and capacity of pipelines and other transportation facilities, and other factors that result in differentials to benchmark prices from time to time;
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the cost of exploring for, developing, producing and transporting reserves;
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the price and quantity of foreign imports;
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political and economic conditions in oil producing countries;
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the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
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speculative trading in crude oil and natural gas derivative contracts;
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the level of consumer product demand;
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weather conditions and other natural disasters;
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risks associated with operating drilling rigs;
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technological advances affecting exploration and production operations and overall energy consumption;
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domestic and foreign governmental regulations and taxes;
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the continued threat of terrorism and the impact of military and other action;
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the price and availability of competitors’ supplies of oil and natural gas and alternative fuels; and
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overall domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. For example, for the five years ended December 31, 2015, the NYMEX-WTI oil future price ranged from a high of $113.93 per Bbl to a low of $34.73 per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $6.15 per MMBtu to a low of $1.76 per MMBtu. Recently, oil and natural gas prices have declined significantly. Through December 31, 2015, the West Texas Intermediate posted price had declined from a high of $61.43 per Bbl on June 10, 2015 to $34.73 per Bbl on December 18, 2015. In addition, the Henry Hub spot market price had declined from a high of $3.23 per MMBtu on January 14, 2015 to a low of $1.76 per MMBtu on December 17, 2015. From January 1, 2016 through January 31, 2016, the West Texas Intermediate posted price dropped to a low of $26.55 per Bbl on January 20, 2016 and the Henry Hub spot market price dropped to a low of $2.09 per MMBtu on January 19, 2016. Likewise, NGLs have suffered significant recent declines in realized prices. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics. A further or extended decline in commodity prices could materially and adversely affect our business, results of operations and financial condition and could cause us to reduce the distributions we pay to our unitholders or to cease paying distributions.
If commodity prices decline further and remain depressed for a prolonged period, a significant portion of our development projects may become uneconomic and cause further write downs of the value of our oil and natural gas properties, which may adversely affect our financial condition and our ability to make distributions to our unitholders.
As discussed above, recently oil, natural gas and NGL prices have declined significantly. A further or extended decline in commodity prices could render many of our development and production projects uneconomical and result in a downward adjustment of our reserve estimates, which would reduce our borrowing base and our ability to pay distributions to our unitholders or fund our operations.
We recognized $616.8 million of impairments during 2015 and $407.5 million of impairments during 2014 related to certain properties in East Texas, South Texas, the Permian Basin, Wyoming and Colorado. A further or extended decline in commodity prices may cause us to recognize additional impairments in the value of our oil and natural gas properties. In addition, if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We have incurred impairment charges recently, and we may in the future incur impairment charges that could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our revolving credit facility and could cause us to reduce the distributions we pay to our unitholders or to cease paying distributions.
Based on our most recent impairment assessment, the undiscounted cash flows for certain of our properties did not exceed the carrying value by a significant margin or cushion. This is an indicator that further impairments may need to be recognized during 2016. We believe that any impairments recognized during 2016 could be comparable to the amounts we recognized during 2015 and 2014.
Unless we replace the oil and natural gas reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.
We will be unable to sustain our current distribution rate without substantial capital expenditures that maintain our asset base. Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production and therefore our cash flow and ability to make distributions are highly dependent on our success in efficiently developing and exploiting our current reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we drill additional wells or make acquisitions. We may not be able to develop, find or acquire additional reserves to replace our current and future production at economically acceptable terms, which would adversely affect our business, financial condition and results of operations and reduce cash available for distribution to our unitholders.
Our acquisition and development operations require substantial capital expenditures.
The development and production of our oil and natural gas reserves requires substantial capital expenditures, which will reduce the amount of cash available for distribution to our unitholders. Further, if the borrowing base under our revolving credit facility decreases, or our revenues decrease, as a result of lower oil or natural gas prices or for any other reason, we may not be able to obtain the capital necessary to sustain our operations at the level necessary to generate cash sufficient to make distributions to our unitholders at our current rate or at all.
Our hedging strategy may not effectively mitigate the impact of commodity price volatility from our cash flows, and our hedging activities could result in cash losses and may limit potential gains.
We intend 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 in time. These commodity derivative contracts include natural gas, oil and NGL financial swaps and collar contracts and natural gas basis financial swaps. The prices and quantities at which we enter into commodity derivative contracts covering our production in the future will be dependent upon oil and natural gas prices, and price expectations, at the time we enter into these transactions, which may be substantially higher or lower than current or future oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Many of the derivative contracts to which we will be a party will require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil and natural gas prices. If our actual production and sales for any period are less than our hedged production and sales for that period (including reductions in production due to operational delays) or if we are unable to perform our drilling activities as planned, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, which may materially impact our liquidity.
Our hedging transactions expose us to counterparty credit risk.
Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets or other unforeseen events could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of a derivative contract and, accordingly, prevent us from realizing the benefit of such a derivative contract.
An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could significantly reduce our cash available for distribution and adversely affect our financial condition.
The prices that we receive for our oil and natural gas production often reflect a regional discount, based on the location of production, to the relevant benchmark prices, such as NYMEX or ICE, that are used for calculating hedge positions. The prices we receive for our production are also affected by the specific characteristics of the production relative to production sold at benchmark prices. For example, our California oil typically has a lower gravity, and a portion has higher sulfur content, than oil sold at certain benchmark prices. Therefore, because our oil requires more complex refining equipment to convert it into high value products, it may sell at a discount to those prices. These discounts, if significant, could reduce our cash available for distribution to our unitholders and adversely affect our results of operations and financial condition.
Our estimated reserves and future production rates are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.
It is not possible to measure underground accumulations of oil or natural gas in an exact way. The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect our estimated quantities and present value of our reserves.
In order to prepare our estimates, we must project production rates and timing of operating and development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary.
The process also requires economic assumptions about matters such as natural gas and oil prices, drilling and operating expenses, capital expenditures and availability of funds.
Actual future production, oil prices, natural gas prices, revenues, development expenditures, operating expenses and quantities of recoverable reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust our reserve estimates to reflect production history, results of development, existing commodity prices and other factors, many of which are beyond our control.
You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from our reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.
Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves.
The present value of future net cash flows from our proved reserves shown in this report, or standardized measure, may not be the current market value of our estimated natural gas and oil reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board (“FASB”), we base the estimated discounted future net cash flows from our proved reserves on the trailing 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements, which is required by the FASB, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.
Developing and producing oil and natural gas are costly and high-risk activities with many uncertainties that may result in a total loss of investment or otherwise adversely affect our business, financial condition, results of operations and cash available for distribution.
Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry holes, but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then-realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of our development and production activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our development and production operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:
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high costs, shortages or delivery delays of rigs, equipment, labor, electrical power or other services;
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unusual or unexpected geological formations;
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composition of sour natural gas, including sulfur, carbon dioxide and other diluent content;
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unexpected operational events and conditions;
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failure of down hole equipment and tubulars;
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loss of wellbore mechanical integrity;
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failure, unavailability or shortage of capacity of gathering pipeline, particularly from the Beta properties, or other transportation facilities;
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human errors, facility or equipment malfunctions and equipment failures or accidents, including acceleration of deterioration of our facilities and equipment due to the highly corrosive nature of sour natural gas;
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title problems;
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loss of drilling fluid circulation;
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hydrocarbon or oilfield chemical spills;
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fires, blowouts, surface craterings and explosions;
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surface spills or underground migration due to uncontrollable flows of oil, natural gas, formation water or well fluids;
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delays imposed by or resulting from compliance with environmental and other governmental or regulatory requirements; and
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adverse weather conditions and natural disasters.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and cash available for distribution to our unitholders may be adversely affected. If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and cash available for distribution to our unitholders.
The production from our Wyoming Bairoil properties could be adversely affected by the cessation or interruption of the supply of CO2 to those properties.
We inject water and CO2 into formations on substantially all of the Wyoming Bairoil properties to increase production of oil and natural gas. The additional production and reserves attributable to the use of enhanced recovery methods are inherently difficult to predict. If we are unable to produce oil and gas by injecting CO2 in the manner or to the extent that we anticipate, our future results of operations and financial condition could be materially adversely affected. Additionally, our ability to utilize CO2 to enhance production is subject to our ability to obtain sufficient quantities of CO2. If, under our CO2 supply contracts, the supplier is unable to deliver its contractually required quantities of CO2 to us, or if our ability to access adequate supplies is impeded, then we may not have sufficient CO2 to produce oil and natural gas in the manner or to the extent that we anticipate, and our future oil and gas production volumes will be negatively impacted.
Many of our properties are in areas that may have been partially depleted or drained by offset wells.
Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests lying contiguous or adjacent to or adjoining any of our properties could take actions, such as drilling additional wells that could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves, and may inhibit our ability to further exploit and develop our reserves.
Our expectations for future development activities are planned to be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.
We have identified drilling, recompletion and development locations and prospects for future drilling, recompletion and development. These drilling, recompletion and development locations represent a significant part of our future drilling and enhanced recovery opportunity plans. We cannot predict in advance of drilling, testing and analysis of data whether any particular drilling location will yield production in sufficient quantities to recover drilling or completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas reserves exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. Our ability to drill, recomplete and develop locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, the generation of additional seismic or geological information, the availability of drilling rigs, drilling results, construction of infrastructure and lease expirations. Because of these uncertainties, we cannot be certain of the timing of these activities or that they will ultimately result in the realization of estimated proved reserves or meet our expectations for success. As such, our actual drilling and enhanced recovery activities may materially differ from our current expectations, which could have a significant adverse effect on our estimated reserves, financial condition and results of operations, and as a result, our ability to make cash distributions to our unitholders.
Part of our strategy involves using horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include, but are not limited to, the following:
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landing our wellbore in the desired drilling zone;
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staying in the desired drilling zone while drilling horizontally through the formation;
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running our casing the entire length of the wellbore; and
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being able to run tools and other equipment consistently through the horizontal wellbore.
Risks that we face while completing our wells include, but are not limited to, the following:
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the ability to fracture stimulate the planned number of stages;
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the ability to run tools the entire length of the wellbore during completion operations; and
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the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.
If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties, and the value of our undeveloped acreage could decline in the future.
Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical, which could have a material adverse impact on our financial condition, results of operations and cash available for distribution.
SEC rules could limit our ability to book additional PUDs in the future.
SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and will likely continue to limit our ability to book additional PUDs as we pursue our drilling program, especially in a time of depressed commodity prices. Moreover, we may be required to write down our PUDs if we do not drill those wells within the required five-year timeframe.
The unavailability or high cost of rigs, equipment, supplies and crews could delay our operations, increase our costs and delay forecasted revenue.
Our industry is cyclical, and historically there have been periodic shortages of rigs, equipment, supplies and crew. Sustained declines in oil and natural gas prices may reduce the number of service providers for such rigs, equipment, supplies and crews, contributing to or resulting in shortages. Alternatively, during periods of higher oil and natural gas prices, the demand for rigs, equipment, supplies and crews is increased and can lead to shortages of, and increasing costs for, development equipment, supplies, services and personnel. Shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict Memorial Resource’s ability to drill the wells and conduct the operations that it currently has planned relating to the fields where our properties are located. In addition, some of our operations require supply materials for production, such as CO2, which could become subject to shortages and increased costs. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues and impact our development plan, which would thus affect our financial conduction, results of operations and our cash available for distribution to our unitholders.
If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase distributions will be limited.
Our ability to grow and to increase distributions to our unitholders depends in part on our ability to make acquisitions that result in an increase in available cash per unit. We may be unable to make such acquisitions because we are:
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unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with their owners;
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unable to obtain financing for such acquisitions on economically acceptable terms; or
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outbid by competitors.
If we are unable to acquire properties containing estimated proved reserves, our total level of estimated proved reserves will decline as a result of our production, and we will be limited in our ability to increase or possibly even to maintain our level of cash distributions to our unitholders.
Any acquisitions we complete will be subject to substantial risks.
One of our growth strategies is to acquire additional oil and natural gas reserves from time to time. Even if we do make acquisitions that we believe will increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash per unit. Any acquisition involves potential risks, including, among other things:
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the validity of our assumptions about estimated proved reserves, future production, revenues, capital expenditures, operating expenses and costs;
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an inability to successfully integrate the assets or businesses we acquire;
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a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;
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a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
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the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;
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mistaken assumptions about the overall cost of equity or debt;
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potential lack of operating experience in the geographic market where the acquired assets or business are located;
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an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and
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the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data and other information, the results of which are often inconclusive and subject to various interpretations. Our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition, given time constraints imposed by sellers. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.
We may incur losses as a result of title defects in the properties in which we invest.
The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.
Expenses not covered by our insurance could have a material adverse effect on our financial position, results of operations and cash available for distribution.
Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including natural disasters, the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, all of which could cause substantial financial losses. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The location of any properties and other assets near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. The occurrence of any of these or other similar events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension or disruption of operations, substantial revenue losses and repairs to resume operations.
We maintain insurance coverage against potential losses that we believe is customary in the industry. However, insurance against all operational risk is not available to us. These insurance policies may not cover all liabilities, claims, fines, penalties or costs and expenses that we may incur in connection with our business and operations, including those related to environmental claims. Pollution and environmental risks generally are not fully insurable. In addition, we cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. A loss not fully covered by insurance could have a material adverse effect on our business, financial position, results of operations and cash available for distribution.
Development and production of oil and natural gas in offshore waters has inherent and historically higher risk than similar activities onshore.
Our offshore operations are subject to a variety of operating risks specific to the marine environment, such as a dependence on a limited number of electrical transmission lines, as well as capsizing, collisions and damage or loss from adverse weather conditions. Offshore activities are subject to more extensive governmental regulation than our other oil and natural gas activities. We are vulnerable to the risks associated with operating offshore California, including risks relating to:
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natural disasters such as earthquakes, mudslides, fires and floods;
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oil field service costs and availability;
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compliance with environmental and other laws and regulations;
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remediation and other costs resulting from oil spill releases of hazardous materials and other environmental damages; and
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failure of equipment or facilities.
In addition to lost production and increased costs, these hazards could cause serious injuries, fatalities, contamination or property damage for which we could be held responsible. The potential consequences of these hazards are particularly severe for us because a significant portion of our offshore operations are conducted in environmentally sensitive areas, including areas with significant residential populations. An accidental oil spill or release on or related to offshore properties and operations could expose us to joint and several strict liability, without regard to fault, under applicable law for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. If an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and damages could be material to our business, financial condition or results of operations and could subject us to criminal and civil penalties. Finally, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation and development operations to be curtailed while those activities are being completed.
Adverse developments in our operating areas would reduce our ability to make distributions to our unitholders.
Our properties are located in Texas, Louisiana, offshore Southern California, Colorado and Wyoming. An adverse development in the oil and natural gas business of any of these geographic areas, such as in our ability to attract and retain field personnel or in our ability to comply with local regulations, could have an impact on our results of operations and cash available for distribution to our unitholders.
We are dependent upon a small number of significant customers for a substantial portion of our production sales. The loss of those customers, if not replaced, could reduce our revenues and have a material adverse effect on our financial condition and results of operations.
We had three customers that each accounted for 10% or more of total reported revenues for the year ended December 31, 2015. The loss of these customers or any significant customer, should we be unable to replace them, could adversely affect our revenues and have a material adverse effect on our financial condition, results of operations and ability to make cash distributions. Also, if any significant customer reduces the volume it purchases from us, we could experience a temporary interruption in sales of, or may receive a lower price for, our production, and our revenues and cash available for distribution could decline, which could adversely affect our ability to make cash distributions to our unitholders at the then-current distribution rate or at all. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have access to suitably liquid markets for our future production. See “Item 1. Business - Operations - Marketing and Major Customers.”
The inability of our significant customers to meet their obligations to us may adversely affect our financial results.
We are subject to credit risk due to concentration of our oil and natural gas receivables. The inability or failure of our significant customers, or any purchasers of our production, to meet their payment obligations to us or their insolvency or liquidation could have a material adverse effect on our results of operations. To the extent that purchasers of our production rely on access to the credit or equity markets to fund their operations, there could be an increased risk that those purchasers could default in their contractual obligations to us. If for any reason we were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of our production were uncollectible, we would recognize a charge in the earnings of that period for the probable loss and could suffer a material reduction in our liquidity and ability to make distributions to our unitholders.
We may experience a financial loss if Memorial Resource is unable to sell, or receive payment for, a significant portion of our oil and natural gas production.
Under our omnibus agreement, Memorial Resource handles sales of our natural gas, oil and NGL production on our behalf. These sales depend upon the demand for natural gas, oil and NGLs from potential purchasers of our production. In recent years, a number of energy marketing and trading companies have discontinued their marketing and trading operations, which has significantly reduced the number of potential purchasers for our production. This reduction in potential customers has reduced overall market liquidity. If any one or more of our significant customers reduces the volume of oil and natural gas production it purchases and other purchasers are unable to be found, then the volume of our production sold on our behalf could be reduced, and we could experience a material decline in cash available for distribution.
We are exposed to trade credit risk in the ordinary course of our business activities.
We are exposed to risks of loss in the event of nonperformance by our vendors and other counterparties. Some of our vendors and other counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors and other counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our vendors’ and other counterparties’ liquidity and ability to make payments or perform on their obligations to us. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors and/or counterparties could reduce our ability to make distributions to our unitholders and adversely affect our business, financial condition, results of operations and cash flows.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
We may be unable to compete effectively with larger companies.
The oil and natural gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas, and securing equipment and trained personnel. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis, and many of our competitors have access to capital at a lower cost than that available to us. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Furthermore, we may not be able to aggregate sufficient quantities of production to compete with larger companies that are able to sell greater volumes of production to intermediaries, thereby reducing the realized prices attributable to our production. Any inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations and our ability to make distributions to our unitholders.
Our business depends in part on pipelines, gathering systems and processing facilities owned by us or others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and natural gas production.
The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of pipelines and other transportation methods, gathering systems and processing facilities owned by third parties. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of contracted capacity on such systems. For example, our ability to produce and sell oil from the Beta properties will depend on the availability of the pipeline infrastructure between platforms as well as the San Pedro Bay pipeline for delivery of that oil to shore, and any unavailability of that pipeline infrastructure or pipeline could cause us to shut in all or a portion of the production from the Beta properties for the length of such unavailability. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided with only limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation or processing facility capacity could reduce our ability to market our oil and natural gas production and harm our business, financial condition, results of operations and cash available for distribution.
The operation of our properties is largely dependent on the ability of Memorial Resource’s employees.
The continuing production from our properties, and to some extent the marketing of our production, is dependent upon the ability of the operators of our properties. Memorial Resource operates substantially all of our properties, either directly as operator or, where we are the operator of record, on our behalf under the omnibus agreement. As of December 31, 2015, based on proved reserve volumes, we and Memorial Resource operated 95% and third parties operated 5% of the wells and properties in which we have interests. As a result, the success and timing of drilling and development activities on such properties, depend upon a number of factors, including:
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the nature and timing of drilling and operational activities;
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the timing and amount of capital expenditures;
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Memorial Resource’s or the operators’ expertise and financial resources;
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the approval of other participants in such properties; and
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the selection and application of suitable technology.
If Memorial Resource or the applicable third-party operator is unable to conduct drilling and development activities on our properties on a timely basis, we may be unable to increase our production or offset normal production declines, or we will be required to write off the estimated proved reserves attributable thereto, any of which may adversely affect our production, revenues and results of operations and our cash available for distribution. Any such write-offs of our reserves could reduce our ability to borrow money and could adversely impact our ability to pay distributions on the common units.
Where we are operator of the wells located on our properties, our operations will be generally governed by operating agreements if any third party has interests in these properties, which agreements typically require the operator to conduct operations in a good and workmanlike manner. For the wells located on our properties that Memorial Resource or a third party is the operator, the operator will generally not be a fiduciary with respect to us or our unitholders. As an owner of working interests in properties not operated by us, we will generally have a cause of action for damages arising from a breach of the operator’s duty.
We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.
Our oil and natural gas development and production operations are subject to complex and stringent laws and regulations administered by governmental authorities vested with broad authority relating to the exploration for, and the development, production and transportation of, oil and natural gas, as well as environmental and safety matters. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and thus, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.
Our oil and natural gas development and production operations are also subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, worker health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, seismically active areas, and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue.
Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly owned or operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.
Our oil and gas operations associated with our Beta properties are conducted on offshore leases in federal waters. Federal offshore leases are administered by Bureau of Ocean Energy Management, or BOEM. Holders of federal offshore leases are required to comply with detailed BOEM regulations, Bureau of Safety and Environmental Enforcement, or BSEE, regulations and the Outer Continental Shelf Lands Act (OCSLA), which are subject to interpretation and change. Lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard and the EPA. The BSEE has regulations requiring offshore production facilities and pipelines located on the outer continental shelf to meet stringent engineering and construction specifications, and has proposed and/or promulgated additional safety related regulations concerning the design and operating procedures of these facilities and pipelines, including regulations to safeguard against or respond to well blowouts and other catastrophes. BSEE regulations also restrict the flaring or venting of natural gas and prohibit the flaring of liquid hydrocarbons and oil without prior authorization.
The BSEE has regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities. The BSEE generally requires that lessees have substantial net worth, post supplemental bonds or provide other acceptable assurances that the obligations will be met. If we fail to pay royalties or comply with safety and environmental regulations, the BOEM and BSEE may require that our operations on the Beta properties be suspended or terminated, and we may be subject to civil or criminal penalties.
On January 29, 2016, BOEM and BSEE entered into a settlement agreement with environmental groups promising to study the potential environmental impacts of well-stimulation practices on the Pacific OCS, including hydraulic fracturing and acid well stimulation. Pending completion of this study, which is expected by May 28, 2016, BSEE will withhold approvals of future permit applications involving hydraulic fracturing operations or acid well stimulation on the Pacific OCS. Delays in the approval or refusal of plans and issuance of permits by the BOEM or BSEE because of staffing, economic, environmental or other reasons (or other actions taken by the BOEM or BSEE) could adversely affect our offshore operations. The requirements imposed by BOEM and BSEE regulations are frequently changed and subject to new interpretations.
Our operations on federal, state or Indian oil and natural gas leases must comply with numerous regulatory restrictions, including various non-discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Department of the Interior’s Bureau of Land Management, or the BLM, BOEM, BSEE, Bureau of Indian Affairs, tribal or other appropriate federal, state and/or Indian tribal agencies.
The Mineral Leasing Act of 1920, as amended, or the Mineral Act, prohibits ownership of any direct or indirect interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign entity except through equity ownership in a corporation formed under the laws of the United States or of any U.S. State or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or entities of the United States. If these restrictions are violated, the oil and natural gas lease can be canceled in a proceeding instituted by the United States Attorney General. We qualify as an entity formed under the laws of the United States or of any U.S. State or territory. Although the regulations promulgated and administered by the BLM pursuant to the Mineral Act provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. It is possible that our unitholders may be citizens of foreign countries who do not own their units in a U.S. corporation, or that even if such units are held through a U.S. corporation, their country of citizenship may be determined to be non-reciprocal countries under the Mineral Act. In such event, any federal onshore oil and natural gas leases held by us could be subject to cancellation based on such determination.
Climate change legislation or regulations restricting emissions of “greenhouse gases,” or GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce.
In December 2009, the EPA published its findings that emissions of greenhouse gases, of GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the federal Clean Air Act, or CAA, that establish Prevention of Significant Deterioration, or PSD, and Title V permit reviews for GHG emissions from certain large stationary sources. On June 23, 2014, the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their GHG emissions. The Court ruled, however, that the EPA may require installation of best available control technology for GHG emissions at sources otherwise subject to the PSD or Title V programs. On December 19, 2014, the EPA issued two memoranda providing initial guidance on GHG permitting requirements in response to the Court’s decision. In its preliminary guidance, the EPA indicated that it would promulgate a rule to rescind any PSD permits issued under the portions of the tailoring rule that were vacated by the Court. In the interim, the EPA issued a narrowly crafted “no action assurance” indicating it will exercise its enforcement discretion not to pursue enforcement of the terms and conditions relating to GHGs in an EPA-issued PSD permit, and for related terms and conditions in a Title V permit. On April 30, 2015, the EPA issued a final rule allowing permitting authorities to rescind PSD permits issued under the invalid regulations.
The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources on an annual basis in the United States, including, among others, certain oil and natural gas production facilities, which includes certain of our operations. In addition, the EPA has continued to adopt GHG regulations applicable to other industries, such as its August 2015 adoption of three separate, but related, actions to address carbon dioxide pollution from power plants. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, almost one-half of the states have taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. In addition, the Obama administration has announced in its Climate Action Plan that it intends to adopt additional regulations to reduce emissions of GHGs in the coming years, possibly including further restrictions on emissions of methane from oil and gas operations.
In December 2015, the United States joined the international community at the 21st Conference of the Parties (COP-21) of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Agreement, if ratified, establishes a framework for the parties to cooperate and report actions to reduce GHG emissions.
Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. See “Item 1. Business - Environmental, Health and Safety Matters and Regulations” and “- Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us.
The listing of a species as either “threatened” or “endangered” under the federal Endangered Species Act could result in increased costs, new operating restrictions, or delays in our operations, which could adversely affect our results of operations and financial condition.
The federal Endangered Species Act (“ESA”) and analogous state laws regulate activities that could have an adverse effect on threatened and endangered species. Operations in areas where threatened or endangered species or their habitat are known to exist may require us to incur increased costs to implement mitigation or protective measures and also may restrict or preclude our activities in those areas or during certain seasons, such as breeding and nesting seasons. On March 27, 2014, the U.S. Fish and Wildlife Service (“FWS”) announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas, and Colorado, where we conduct operations, as a threatened species under the ESA. Listing of the lesser prairie chicken as threatened imposes restrictions on disturbances to critical habitat by landowners and drilling companies that would harass, harm or otherwise result in a “taking” of this species. However, the FWS’s listing decision is currently subject to at least three lawsuits. On September 1, 2015, the U.S. District Court for the Western District of Texas overturned the listing of the lesser prairie chicken, holding that the FWS’s decision had been arbitrary and capricious and not consistent with its own policies. The FWS has requested that the Court amend its judgment to allow the agency to substantiate or reconsider its action.
The FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies (“WAFWA”), pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. The listing of the lesser prairie chicken as a threatened species or, alternatively, entry into certain range-wide conservation planning agreements such as WAFWA, could result in increased costs to us from species protection measures, time delays or limitations on our activities, which costs, delays or limitations may be significant and could adversely affect our results of operations and financial position.
The third parties on whom we rely for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.
The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders. See “Item 1. Business - Environmental, Health and Safety Matters and Regulations” and “- Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect the third parties on whom we rely.
Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with our business.
The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission, or CFTC, the SEC, and federal regulators of financial institutions, or the Prudential Regulators, adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives activities.
Although some of the rules necessary to implement the Dodd-Frank Act remain to be adopted, the CFTC, the SEC and the Prudential Regulators have issued a large number of rules to implement the Dodd-Frank Act, including a rule, which we refer to as the “Clearing Rule,” requiring clearing of hedges, or swaps, that are subject to it (currently, only certain interest rate and credit default swaps, which we do not presently have), a rule establishing an “end user” exception to the Clearing Rule, referred to herein as the “End User Exception,” a rule, which we refer to as the “Margin Rule,” setting forth collateral requirements in connection with swaps that are not cleared and also an exception to the Margin Rule for end users that are not financial end users, which exception we refer to as the “Non-Financial End User Exception,” and a rule, subsequently vacated by the United States District Court for the District of Columbia and remanded to the CFTC for further proceedings, imposing position limits. The CFTC has proposed a new version of this rule, which we refer to as the “Re-Proposed Position Limit Rule,” with respect to which the comment period has closed but a final rule has not been issued.
We qualify for the End User Exception and will utilize it if the Clearing Rule is expanded to cover swaps in which we participate, we qualify for the Non-Financial End User Exception and will not be required to post margin under the Margin Rule and the quantities under the swaps in which we participate are well within applicable limits under the Re-Proposed Position Limit Rule, so we do not expect to be directly affected by such rules. However, most if not all of our hedge counterparties will be subject to mandatory clearing in connection with their hedging activities with parties who do not qualify for the End User Exception and will be required to post margin in connection with their hedging activities with other swap dealers, major swap participants, financial end users and other persons that do not qualify for the Non-Financial End User Exception. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations, which we refer to collectively as “Foreign Regulations” which may apply to our transactions with counterparties subject to such Foreign Regulations. The Dodd-Frank Act, the rules which have been adopted and not vacated, and, to the extent that the Re-Proposed Position Limit Rule is ultimately effected, such proposed rule could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. The Foreign Regulations could have similar effects. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations and Foreign Regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.
Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Restrictions on the ability to obtain water may impact our operations.
Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our development and production operations, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. The Federal Water Pollution Control Act (the “CWA”) imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The CWA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. State and federal discharge regulations prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. Also, the EPA has adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays, and adversely affect our production.
Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. We routinely apply hydraulic fracturing techniques in our drilling and completion programs.
While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. For example, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities under the Safe Drinking Water Act, or the SDWA, involving the use of diesel fuels and published permitting guidance in February 2014 addressing the use of diesel in fracturing operations. Although the EPA is not the permitting authority for the SDWA’s Underground Injection Control Class II programs in Louisiana, Texas, Wyoming, or Colorado, where we or Memorial Resource maintain operational acreage, the EPA is encouraging state programs to review and consider use of such draft guidance. Also, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking public comment on its intent to develop and issue regulations under the Toxic Substances Control Act regarding the disclosure of information related to the chemicals used in hydraulic fracturing. The public comment period ended on September 18, 2014. The EPA plans to develop a Notice of Proposed Rulemaking by December 2016, which would describe a proposed mechanism - regulatory, voluntary, or a combination of both - to collect data on hydraulic fracturing chemical substances and mixtures.
Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting “flowback,” as well as “produced water.” On April 7, 2015, the EPA published a proposed rule establishing federal pre-treatment standards for wastewater discharged from onshore unconventional oil and gas extraction facilities to publicly owned treatment works (“POTW”). The EPA asserts that wastewater from such facilities can be generated in large quantities and can contain constituents that may disrupt POTW operations and/or be discharged, untreated, from the POTW to receiving waters. If adopted, the new pre-treatment rule would require unconventional oil and gas facilities to pre-treat wastewater before transferring it to a POTW. The public comment period ended on July 17, 2015, and the EPA is expected to publish a final rule by August 2016. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.
In August 2012, the EPA published final rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants programs. The rules include NSPS standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rules seek to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of these requests for reconsideration. For example, in September 2013 and December 2014, the EPA amended its rules to extend compliance deadlines and to clarify the NSPS. In addition, on September 18, 2015, the EPA published a suite of proposed rules to reduce methane and VOC emissions from oil and gas industry, including new “downstream” requirements covering equipment in the natural gas transmission segment of the industry that was not regulated by the 2012 rules. The public comment period closed on December 4, 2015. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.
In addition, on March 26, 2015, the federal Bureau of Land Management, or BLM, published a final rule governing hydraulic fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic fracturing, implementation of a casing and cementing program, management of recovered fluids, and submission to the BLM of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, and the depths of all usable water. This rule took effect on June 24, 2015, although it is the subject of several pending lawsuits filed by industry groups and at least four states, alleging that federal law does not give the BLM authority to regulate hydraulic fracturing. On September 30, 2015, the United States District Court for Wyoming issued a preliminary injunction preventing the BLM from implementing the rule nationwide. This order has been appealed to the Tenth Circuit Court of Appeals. Also, on January 22, 2016, the BLM announced a proposed rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands. The proposed rule would require operators to use currently available technologies and equipment to reduce flaring, periodically inspect their operations for leaks, and replace outdated equipment that vents large quantities of gas into the air. The rule would also clarify when operators owe the government royalties for flared gas.
Additionally, Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Certain states, including Texas and Louisiana, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. For example, in October 2011, the Louisiana Department of Natural Resources adopted new rules requiring the public disclosure of the composition and volume of fracturing fluids used in hydraulic fracturing operations. Also, Texas requires oil and natural gas operators to disclose to the Railroad Commission of Texas and the public the chemicals used in the hydraulic fracturing process, as well as the total volume of water used. Furthermore, in May 2013, the Texas Railroad Commission adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Additionally, on October 28, 2014, the Commission adopted disposal well rule amendments designed, amongst other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed, new disposal well. The disposal well rule amendments, which became effective on November 17, 2014, also clarify the Commission’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Commission has used this authority to deny permits for waste disposal wells. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.
If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill wells. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. The U.S. Congress has from time to time considered legislation to amend the SDWA, including legislation that would repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.
Certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices, which could lead to increased regulation. For example, the EPA is currently evaluating the potential impacts of hydraulic fracturing on drinking water resources. In June 2015, the EPA released its draft assessment report for peer review and public comment, finding that, while there are certain mechanisms by which hydraulic fracturing activities could potentially impact drinking water resources, there is no evidence available showing that those mechanisms have led to widespread, systemic impacts. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. In addition, as discussed above, BOEM and BSEE are studying the potential environmental impacts of well-stimulation practices on the Pacific OCS. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.
The cost of decommissioning is uncertain.
We are required to maintain reserve funds to provide for the payment of decommissioning costs associated with the Beta properties. The estimates of decommissioning costs are inherently imprecise and subject to change due to changing cost estimates, oil and natural gas prices and other factors. If actual decommissioning costs exceed such estimates, or we are required to provide a significant amount of collateral in cash or other security as a result of a revision to such estimates, our financial condition, results of operations and cash flows may be materially adversely affected.
Increases in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.
Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Also, as with other yield-oriented securities, our unit price is impacted by the level of our cash distributions to our unitholders and the implied distribution yield. The distribution yield is often used by investors to compare and rank similar yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue additional equity or incur debt, and the cost to us of any such issuance or incurrence.
Our business could be adversely affected by security threats, including cyber-security threats, and related disruptions.
We rely heavily on our information systems, and the availability and integrity of these systems are essential for us to conduct our business and operations. As a producer of natural gas and oil, we face various security threats, including cyber-security threats, to gain unauthorized access to our sensitive information or to render our information or systems unusable, and threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as gathering and processing and other facilities, refineries and pipelines. The potential for such security threats subjects our operations to increased risks that could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our implementation of various procedures and controls to monitor and mitigate such security threats and to increase security for our information, systems, facilities and infrastructure may result in increased costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of, or damage to, sensitive information or facilities, infrastructure and systems essential to our business and operations, as well as data corruption, communication interruptions or other disruptions to our operations, which, in turn, could have a material adverse effect on our business, financial position, results of operations and cash flows.
Risks Inherent in an Investment in Us
Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of our unitholders.
Our general partner has control over all decisions related to our operations. Memorial Resource owns 100% of the voting membership interests in our general partner. The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to the owners of our general partner. However, certain directors and officers of our general partner are directors and/or officers of affiliates of our general partner (including Memorial Resource, the Funds and NGP), and certain of our general partner’s executive officers and directors will continue to have economic interests, investments and other economic incentives in the Funds and other NGP-affiliated entities. Conflicts of interest may arise in the future between our general partner and its affiliates (including Memorial Resource, the Funds and NGP), on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders and us. Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. These potential conflicts include, among others, the following situations:
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neither our partnership agreement nor any other agreement requires Memorial Resource, the Funds or NGP to pursue a business strategy that favors us. The directors and officers of Memorial Resource, the Funds and their respective affiliates (including NGP) have a fiduciary duty to make decisions in the best interests of their respective equity holders, which may be contrary to our interests;
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our general partner is allowed to take into account the interests of parties other than us, such as its owner, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
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Memorial Resource, the Funds and their affiliates (including NGP) are not limited in their ability to compete with us, including with respect to future acquisition opportunities, and are under no obligation to offer assets to us;
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except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
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many of the officers and directors of our general partner who provide services to us devote time to affiliates of our general partner, including Memorial Resource, the Funds, and/or NGP, and may be compensated for services rendered to such affiliates;
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our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without such limitations, reductions, and restrictions, might constitute breaches of fiduciary duty. By purchasing common units, unitholders are consenting to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;
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our general partner determines the amount and timing of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership interests, other investments, including investment capital expenditures in other partnerships with which our general partner is or may become affiliated, and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to unitholders;
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our general partner determines whether a cash expenditure is classified as a growth capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the amount of adjusted operating surplus in any given period;
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we and our general partner have entered into an omnibus agreement with Memorial Resource, pursuant to which among other things, Memorial Resource operates our assets and performs other management, administrative, and operating services for us and our general partner;
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our general partner is entitled to determine which costs, including allocated overhead, incurred by it and its affiliates, including Memorial Resource, are reimbursable by us, which will include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates;
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our general partner may cause us to borrow funds in order to permit the payment of cash distributions or to make incentive distributions;
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our partnership agreement permits us to classify up to $30.5 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner in respect of the general partner interest or the incentive distribution rights;
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our general partner decides whether to retain separate counsel, accountants, or others to perform services for us;
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our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations;
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our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
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our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;
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our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units; and
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our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including Memorial Resource, the Funds and NGP.
See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”
Memorial Resource, the Funds and other affiliates of our general partner are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses.
Our partnership agreement provides that Memorial Resource and the Funds and their respective affiliates (including NGP and its affiliates’ portfolio investments) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Memorial Resource and the Funds and their respective affiliates may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets.
NGP and the Funds are established participants in the oil and natural gas industry, and have resources greater than ours, which factors may make it more difficult for us to compete with them with respect to commercial activities as well as for potential acquisitions. As a result, competition from these affiliates could adversely impact our results of operations and cash available for distribution to our unitholders. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”
Neither we nor our general partner have any employees and we rely solely on the employees of Memorial Resource to manage our business. The management team of Memorial Resource, which includes individuals who manage us, also performs substantially similar services for Memorial Resource and its assets, and thus is not solely focused on our business.
Neither we nor our general partner have any employees and we rely solely on Memorial Resource to operate our assets. We and our general partner have entered into an omnibus agreement with Memorial Resource, pursuant to which, among other things, Memorial Resource agreed to operate our assets and perform other management, administrative, and operating services for us and our general partner.
Memorial Resource provides substantially similar activities with respect to its own assets and operations. Because Memorial Resource provides services to us that are substantially similar to those performed for itself, Memorial Resource may not have sufficient human, technical and other resources to provide those services at a level that Memorial Resource would be able to provide to us if it were solely focused on our business and operations. Memorial Resource may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to Memorial Resource’s interests. There is no requirement that Memorial Resource favor us over itself in providing its services. If the employees of Memorial Resource do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.
If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.
Many of the directors and officers who have responsibility for our management have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.
To maintain and increase our levels of production, we will need to acquire oil and natural gas properties. Some of the officers of our general partner hold similar positions with Memorial Resource, and many of the directors of our general partner, who are responsible for managing our general partner’s direction of our operations and acquisition activities, hold positions of responsibility with other entities (including NGP-affiliated entities) that are in the business of identifying and acquiring oil and natural gas properties. For example, the Funds and their affiliates (including NGP) are in the business of investing in oil and natural gas companies with independent management teams that also seek to acquire oil and natural gas properties, and Memorial Resource is in the business of acquiring and developing oil and natural gas properties. Mr. Hersh, a director of our general partner, is the Chief Executive Officer of NGP Energy Capital Management and a managing partner of NGP; Mr. Gieselman, a director of our general partner, is a managing director of NGP; Mr. Weber, a director of our general partner, currently serves as Managing Partner and Chief Operating Officer for NGP; and Mr. Weinzierl, the Chief Executive Officer and Chairman of the board of directors of our general partner, was a managing director and operating partner of NGP before our initial public offering and continues to hold ownership interests in the Funds and certain of their affiliates. Some of the officers of our general partner will continue to devote significant time to the business of Memorial Resource. We cannot assure you that any conflicts that may arise between us and our unitholders, on the one hand, and Memorial Resource or the Funds, on the other hand, will be resolved in our favor. The existing positions held by these directors and officers may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These officers and directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our unitholders should be aware, see “Item 13. Certain Relationships and Related Transactions, and Director Independence.”
Cost reimbursements due to Memorial Resource and our general partner for services provided to us or on our behalf will be substantial and will reduce our cash available for distribution to our unitholders.
Our partnership agreement requires us to reimburse our general partner and its affiliates for all actual direct and indirect expenses they incur or actual payments they make on our behalf and all other expenses allocable to us or otherwise incurred by our general partner or its affiliates in connection with operating our business, including overhead allocated to our general partner by its affiliates, including Memorial Resource. These expenses include salary, bonus, incentive compensation (including equity compensation) and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.
Prior to making distributions on our common units, we will reimburse our general partner and its affiliates for all such expenses. None of these reimbursements are capped. The reimbursements to Memorial Resource and our general partner will reduce the amount of cash otherwise available for distribution to our unitholders.
We have entered into an omnibus agreement with Memorial Resource and our general partner pursuant to which, among other things, Memorial Resource provides management, administrative and operating services for us and our general partner. The payments to Memorial Resource pursuant to this agreement will be substantial and will reduce the amount of cash available for distribution to unitholders.
Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors. Memorial Resource, as owner of our general partner, has the power to appoint and remove our general partner’s directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is appointed by Memorial Resource. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Our general partner has control over all decisions related to our operations. Since Memorial Resource owns our general partner, the other unitholders will not have an ability to influence any operating decisions and will not be able to prevent us from entering into any transactions. Since the subordination period has ended, our partnership agreement can be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units. Please read “- Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of our unitholders.”
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
Our general partner has the right (but not the obligation), at any time it has received incentive distributions at the highest level to which it is entitled (25%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following any reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash contribution per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will be equal to that number of common units which would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right (if at all) to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units and general partner units to our general partner in connection with resetting the target distribution levels.
Our unitholders who fail to furnish certain information requested by our general partner or who our general partner determines are not eligible citizens may not be entitled to receive distributions in kind upon our liquidation and their common units will be subject to redemption.
We have the right to redeem all of the units of any holder that is not an eligible citizen if we are or become subject to federal, state, or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property in which we have an interest because of the nationality, citizenship or other related status of any limited partner. Our general partner may require any limited partner or transferee to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation. Furthermore, we have the right to redeem all of the common units of any holder that is not an eligible citizen or fails to furnish the requested information.
Common units held by persons who are non-taxpaying assignees will be subject to the possibility of redemption.
If our general partner determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on our ability to operate our assets or generate revenues from our assets, then our general partner may adopt such amendments to our partnership agreement as it determines are necessary or advisable to obtain proof of the U.S. federal income tax status of our limited partners (and their owners, to the extent relevant) and permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on our ability to operate our assets or generate revenues from our assets or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status.
Our general partner will be required to deduct estimated maintenance capital expenditures from our operating surplus, which may result in less cash available for distribution to unitholders from operating surplus than if actual maintenance capital expenditures were deducted.
Maintenance capital expenditures are those capital expenditures required to maintain our long-term asset base, including expenditures to replace our oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property. Our partnership agreement requires our general partner to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus in determining cash available for distribution from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and change by the conflicts committee of the board of directors of our general partner at least once a year. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders from operating surplus will be lower than if actual maintenance capital expenditures had been deducted from operating surplus. On the other hand, if our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we will have more cash available for distribution from operating surplus in the short term but will have less cash available for distribution from operating surplus in future periods when we have to increase our estimated maintenance capital expenditures to account for the previous underestimation.
Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:
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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation involving us or to any amendment to our partnership agreement;
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provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as such decisions are made in good faith and with the honest belief that the decision was in our best interest;
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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must be (i) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (ii) must be “fair and reasonable” to us, as determined by our general partner in good faith. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;
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provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
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provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner’s board of directors or the conflicts committee of our general partner’s board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
By purchasing a common unit, a unitholder will become bound by the provisions in our partnership agreement, including the provisions discussed above.
Control of our general partner and its incentive distribution rights may be transferred to a third party without unitholder consent. A change of control may result in defaults or other payment obligations under certain of our debt instruments and the triggering of payment obligations under compensation arrangements.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Memorial Resource from transferring all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and thereby influence the decisions made by the board of directors and officers in a manner that may not be aligned with the interests of our unitholders.
In addition, our general partner owns 50% of the outstanding incentive distribution rights, or IDRs, and may transfer them to a third party at any time without the consent of our unitholders. If our general partner transfers its IDRs to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.
A change of control would constitute an event of default under our revolving credit agreement. During the continuance of an event of default under our revolving credit agreement, the administrative agent may terminate any outstanding commitments of the lenders to extend credit to us under our revolving credit facility and/or declare all amounts payable by us under our revolving credit facility immediately due and payable. Certain changes of control would also give rise to an obligation to offer to repurchase all of our outstanding senior notes at 101% of their outstanding principal amounts. A change of control also may trigger payment obligations under various compensation arrangements with our officers.
We may not make cash distributions during periods when we record net income.
The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow, including cash from reserves established by our general partner, working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions to our unitholders during periods when we record net losses and may not make cash distributions to our unitholders during periods when we record net income.
We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval, which would dilute unitholders’ ownership interests.
Our partnership agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:
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our unitholders’ proportionate ownership interest in us will decrease;
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the amount of cash available for distribution on each unit may decrease;
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the ratio of taxable income to distributions may increase;
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the relative voting strength of each previously outstanding unit may be diminished; and
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the market price of our common units may decline.
Our partnership agreement restricts the limited voting rights of unitholders, other than our general partner and its affiliates, owning 20% or more of our common units, which may limit the ability of significant unitholders to influence the manner or direction of management.
Our partnership agreement restricts unitholders’ limited voting rights by providing that any common units held by a person, entity or group that owns 20% or more of any class of common units then outstanding (other than our general partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the board of directors of our general partner) cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.
Our general partner has a call right that may require common unitholders to sell their common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is the greater of (i) the highest cash price paid by either of our general partner or any of its affiliates for any common units purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those common units; and (ii) the average daily closing prices of our common units over the 20 days preceding the date three days before the date the notice is mailed. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders also may incur a tax liability upon a sale of their common units.
If we distribute cash from capital surplus, which is analogous to a return of capital, our minimum quarterly distribution will be reduced proportionately, and the distribution thresholds after which the incentive distribution rights entitle our general partner to an increased percentage of distributions will be proportionately decreased.
Our cash distributions will be characterized as coming from either operating surplus or capital surplus. Operating surplus is defined in our partnership agreement, and generally means amounts we receive from operating sources, such as sale of our oil and natural gas production, less operating expenditures, such as production costs and taxes, and less estimated average maintenance capital expenditures, which are generally amounts we estimate we will need to spend in the future to maintain our production levels over the long term. Capital surplus is defined in our partnership agreement, and generally would result from cash received from non-operating sources such as sales of properties and issuances of debt and equity interests. Cash representing capital surplus, therefore, is analogous to a return of capital. Distributions of capital surplus are made to our unitholders and our general partner in proportion to their percentage interests in us, or 99.9% to our unitholders and 0.1% to our general partner, and will result in a decrease in our minimum quarterly distribution.
Our partnership agreement allows us to add to operating surplus $30.5 million. As a result, a portion of this amount, which is analogous to a return of capital, may be distributed to the general partner and its affiliates, as holders of incentive distribution rights, rather than to holders of common units as a return of capital.
Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for our obligations as if it was a general partner if:
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a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
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a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
Our unitholders may have liability to repay distributions.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make distributions to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.
We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions, and covenants in our revolving credit facility may restrict our ability to make distributions.
Our partnership agreement allows us to borrow to make distributions. We may make short-term borrowings under our revolving credit facility to make distributions. The primary purpose of these borrowings would be to mitigate the effects of short-term fluctuation in our working capital that would otherwise cause volatility in our quarter-to-quarter distributions.
The terms of our revolving credit facility restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the facility.
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production.
Our partnership agreement provides that we will distribute all of our available cash each quarter. As a result, we may be dependent on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:
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general economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds;
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conditions in the oil and natural gas industry;
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the market price of, and demand for, our common units;
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our results of operations and financial condition; and
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prices for oil, NGLs and natural gas.
NASDAQ does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
Our common units are listed on NASDAQ Global Market. Because we are a publicly traded limited partnership, NASDAQ does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of NASDAQ corporate governance requirements.
Tax Risks to Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (IRS) were to treat us as a corporation for federal income tax purposes, our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the units depends largely on our being treated as a partnership for federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.
If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.
Changes in current state law may subject us to additional entity-level state taxation. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are subject to Texas margin tax based on the taxable margin apportioned to Texas. Imposition of any similar taxes by other states in which we conduct business may substantially reduce the cash available for distribution to our unitholders and, therefore, negatively impact the value of an investment in our units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level state income taxes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. In addition, the IRS, on May 5, 2015, issued proposed regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. We do not believe the proposed regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amounts of gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement. Any modification to U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution and the target distribution levels may be adjusted to reflect the impact of that law on us.
Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.
Legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, or IDCs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.
If the IRS contests any of the federal income tax positions we take, the market for our units may be adversely affected, and the costs of any IRS contest will reduce our cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income, which could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, including our taxable income associated with a disposition of property or cancellation of debt, even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on the disposition of our units could be more or less than expected.
If our unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those units. Because distributions in excess of their allocable share of our total net taxable income decrease their tax basis in their units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation, depletion and IDC recapture. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, if they sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts, or IRAs, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. Prospective unitholders who are tax-exempt entities or non-U.S. persons should consult their tax advisor before investing in our units.
We will treat each purchaser of units as having the same tax benefits without regard to the actual units purchased. The IRS may challenge this treatment, which could adversely affect the value of the units.
Because we cannot match transferors and transferees of units and because of other reasons, we will adopt depreciation, depletion and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of units and could have a negative impact on the value of our units or result in audit adjustments to a unitholder’s tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. The Department of the Treasury and the IRS recently adopted final Treasury regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, such regulations do not specifically authorize the use of the proration method we have adopted. Certain publicly traded partnerships, including us, may but are not required to apply the conventions provided by the Treasury regulations. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to have disposed of those units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
We will adopt certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between the general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit will be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. The IRS has announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.
As a result of investing in our units, our unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future even if such unitholders do not live in those jurisdictions. Our unitholders likely will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We currently own property and conduct business in Texas, Louisiana, Colorado, Wyoming and California. We divested our remaining property located in New Mexico during January 2016. Louisiana, California and New Mexico currently impose a personal income tax on individuals. These states also impose an income or franchise tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. We may own property or conduct business in other states or foreign countries in the future. It is a unitholder’s responsibility to file all U.S. federal, state and local tax returns.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Generally, we may elect to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be effective in all circumstances and the manner in which the election is made and implemented has yet to be determined. If we are unable to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced. These rules are not applicable to us for tax years beginning on or prior to December 31, 2017.
Unitholders may have negative tax consequences if we default on our debt or sell assets.
If we default on any of our debt, the lenders will have the right to sue us for non-payment. That action could cause an investment loss and negative tax consequences for our unitholders through the realization of taxable income by unitholders without a corresponding cash distribution. Likewise, if we were to dispose of assets and realize a taxable gain while there is substantial debt outstanding and proceeds of the sale were applied to the debt, our unitholders could have increased taxable income without a corresponding cash distribution.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2.
PROPERTIES
Information regarding our properties is contained in Item 1. Business “-Our Areas of Operation” and “-Our Oil and Natural Gas Data” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations -Results of Operations” contained herein.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
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. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We are not aware of any litigation, pending or threatened, that we believe will have a material adverse effect on our financial position, results of operations or cash flows. No amounts have been accrued at December 31, 2015.
ITEM 4.
ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information and Cash Distributions to Unitholders
Our common units are listed and traded on the NASDAQ Global Market under the symbol “MEMP.” As of January 31, 2016, there were approximately 12 holders of record of our common units.
As reported by the NASDAQ Global Market, the following table shows the low and high sales prices per common unit and the cash distributions declared per common unit for the periods indicated:
We intend to make cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Additionally, under our revolving credit facility, we will not be able to pay distributions to unitholders in any such quarter in the event there exists a borrowing base deficiency or an event of default either before or after giving effect to such distribution or we are not in pro forma compliance with our revolving credit facility after giving effect to such distribution.
See “Item 11. Executive Compensation - Compensation Discussion and Analysis - Elements of Executive Compensation” for additional information concerning grants of restricted common units under the LTIP.
Cash Distribution Policy
Available Cash
Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date.
Available cash generally means, for any quarter prior to liquidation, all cash on hand at the end of the quarter:
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less, the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to:
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provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for capital expenditures, working capital and operating expenses;
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comply with applicable law, any of our debt instruments or other agreements;
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provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters;
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plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter resulting from borrowing made after the end of the quarter.
General Partner Interest and Incentive Distribution Rights
Our general partner is entitled to 0.1% of all distributions of available cash that we make prior to our liquidation. Our general partner’s initial 0.1% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 0.1% general partner interest. Our general partner is not obligated to contribute a proportionate amount of capital to us to maintain its current general partner interest. We have also issued incentive distribution rights (“IDRs”), which entitle the holder(s) thereof to additional increasing percentages, up to a maximum of 24.9% of the cash we distribute in excess of $0.54625 per common unit per quarter. Our general partner owns 50%, and the Funds indirectly own 50%, of the IDRs.
Minimum Quarterly Distribution
Under our partnership agreement, the holders of the IDRs are entitled to incentive distributions if the amount we distribute with respect to one quarter exceeds specified target levels shown below:
(1)
Our general partner owns 50%, and the Funds indirectly own 50%, of the IDRs.
Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period, which ended on February 13, 2015, in the following manner:
·
first, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
·
thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders, the general partner and the holders of the IDRs based on the percentages in the table above.
Unregistered Sales of Equity Securities
Our general partner’s approximate 0.1% interest in us was represented by 86,797 general partner units at December 31, 2015. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its current general partner interest. Issuances of these general partner units would be exempt from registration under Section 4(a)(2) of the Securities Act.
Common Units Authorized for Issuance Under Equity Compensation Plan
See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding securities authorized for issuance under equity compensation plans.
Issuer Purchases of Equity Securities
During the three months ended December 31, 2015, there were no repurchases of our common units. The MEMP Repurchase Program expired in December 2015.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
The following selected financial data should be read in conjunction with “Item 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the financial statements and related notes in “Item 8. Financial Statements and Supplementary Data” contained herein. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences are discussed in “Risk Factors” contained in Part I-Item 1A of this report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Forward-Looking Statements” in the front of this report.
Overview
We are a Delaware limited partnership focused on the ownership, acquisition and development of oil and natural gas properties in North America. The Partnership is owned 99.9% by its limited partners and 0.1% by its general partner, which is a wholly-owned subsidiary of Memorial Resource. Our general partner 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 located in Texas, Louisiana, Colorado, 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:
·
Our total estimated proved reserves were approximately 1,268 Bcfe, of which approximately 43% were oil and 63% were classified as proved developed reserves;
·
We produced from 3,357 gross (1,960 net) producing wells across our properties, with an average working interest of 58%, and the Partnership or Memorial Resource is the operator of record of the properties containing 95% of our total estimated proved reserves; and
·
Our average net production for the three months ended December 31, 2015 was 257.3 MMcfe/d, implying a reserve-to-production ratio of approximately 14 years.
Business Environment and Operational Focus
Our primary business objective is to generate stable cash flows, which will allow us to deliver sustainable quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions as market conditions dictate. 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).
Production Volumes
Production volumes directly impact our results of operations. For more information about our volumes, please read “- Results of Operations” below.
Realized Prices on the Sale of Oil and Natural Gas
We market our oil and natural gas production to a variety of purchasers based on regional pricing. The relative prices of oil and natural gas are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, realized prices are heavily influenced by product quality and location relative to consuming and refining markets.
Natural Gas. The NYMEX-Henry Hub future price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices realized from the sale of natural gas can differ from the quoted NYMEX-Henry Hub price as a result of quality and location differentials. Quality differentials to NYMEX-Henry Hub prices result from: (1) the Btu content of natural gas, which measures its heating value, and (2) the percentage of sulfur, CO2 and other inert content by volume. Natural gas with a high Btu content (“wet” natural gas) sells at a premium to natural gas with low Btu content (“dry” natural gas) because it yields a greater quantity of NGLs. Natural gas with low sulfur and CO2 content sells at a premium to natural gas with high sulfur and CO2 content because of the added cost required to separate the sulfur and CO2 from the natural gas to render it marketable. Wet natural gas may be processed in third-party natural gas plants, where residue natural gas as well as NGLs are recovered and sold. At the wellhead, our natural gas production typically has an average energy content greater than 1,000 Btu and minimal sulfur and CO2 content and generally receives a premium valuation. The dry natural gas residue from our properties is generally sold based on index prices in the region from which it is produced.
Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the produced natural gas’ proximity to the major consuming markets to which it is ultimately delivered. The processing fee deduction retained by the natural gas processing plant also affects the differential. Historically, these index prices have generally been at a discount to NYMEX-Henry Hub natural gas prices.
Oil. The NYMEX-WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The ICE Brent futures price is a widely used global price benchmark for oil. Refiner’s posted prices for California Midway-Sunset deliveries in Southern California is a regional index. The actual prices realized from the sale of oil can differ from the quoted NYMEX-WTI price or California Midway-Sunset price as a result of quality and location differentials. Quality differentials result from the fact that crude oils differ from one another in their molecular makeup, which plays an important part in their refining and subsequent sale as petroleum products. Among other things, there are two characteristics that commonly drive quality differentials: (1) the oil’s American Petroleum Institute, or API, gravity and (2) the oil’s percentage of sulfur content by weight. In general, lighter oil (with higher API gravity) produces a larger number of lighter products, such as gasoline, which have higher resale value, and, therefore, normally sells at a higher price than heavier oil. Oil with low sulfur content (“sweet” oil) is less expensive to refine and, as a result, normally sells at a higher price than high sulfur-content oil (“sour” oil).
Location differentials result from variances in transportation costs based on the produced oil’s proximity to the major consuming and refining markets to which it is ultimately delivered. Oil that is produced close to major consuming and refining markets, such as near Cushing, Oklahoma, is in higher demand as compared to oil that is produced farther from such markets. Consequently, oil that is produced close to major consuming and refining markets normally realizes a higher price (i.e., a lower location differential).
The oil produced from our onshore properties is a combination of sweet and sour oil, varying by location. This oil is typically sold at the NYMEX-WTI price, adjusted for quality and transportation differential, depending primarily on location and purchaser. The oil produced from our Beta properties is sour oil. Oil produced from our Beta properties is currently sold based on refiners’ posted prices for California Midway-Sunset deliveries in Southern California, adjusted primarily for quality and a negotiated market differential. Since 2010, production from our Beta properties has more closely tracked the ICE Brent price, and we have been able to successfully hedge this production through an ICE Brent priced hedge with a corresponding Midway-Sunset basis hedge through 2017.
Price Volatility. In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. The following table shows the low and high commodity future index prices for the periods indicated:
Commodity Derivative Contracts. Our hedging policy is designed to reduce the impact to our cash flows from commodity price volatility. Under this policy, we intend 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 in time. We may, however, from time to time hedge more or less than this approximate range. Additionally, we intend to individually identify these non-speculative hedges as “designated hedges” for U.S. federal income tax purposes as we enter into them, resulting in ordinary income treatment of our realized hedge activity.
Principal Components of Cost Structure
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Lease operating expenses. These are the day to day costs incurred to maintain production of our natural gas, NGLs and oil. Such costs include utilities, direct labor, water injection and disposal, the cost of CO2 injection, materials and supplies, compression, repairs and workover expenses. Cost levels for these expenses can vary based on supply and demand for oilfield services and activities performed during a specific period.
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Gathering, processing and transportation. These are costs incurred to deliver production of our natural gas, NGLs and oil to the market. Cost levels of these expenses can vary based on the volume of natural gas, NGLs and oil production.
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Taxes other than income. These consist of franchise, production and ad valorem taxes. Production taxes are paid on produced natural gas, NGLs and oil based on a percentage of market prices and at fixed per unit rates established by federal, state or local taxing authorities. We take full advantage of all credits and exemptions in the various taxing jurisdictions where we operate. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties. Franchise taxes are privilege taxes levied by states that are imposed on companies, including limited liability companies and partnerships, which gives the businesses the right to be chartered or operate within that state.
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Exploration. These are geological and geophysical costs and include certain seismic costs, costs of unsuccessful exploratory dry holes and unsuccessful leasing efforts.
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Impairment of proved properties. Proved properties are impaired whenever the net carrying value of the properties exceed their estimated undiscounted future cash flows.
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Depreciation, depletion and amortization. Depreciation, depletion and amortization, or DD&A, includes the systematic expensing of the capitalized costs incurred to acquire, exploit and develop oil and natural gas properties. As a “successful efforts” company, all costs associated with acquisition and development efforts and all successful exploration efforts are capitalized, and these costs are depleted using the units of production method.
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General and administrative expense. These costs include overhead, including payroll and benefits for employees, costs of maintaining headquarters, costs of managing production and development operations, compensation expense associated with certain long-term incentive-based plans, audit and other professional fees and legal compliance expenses.
We and our general partner are parties to an omnibus agreement with a wholly-owned subsidiary of Memorial Resource pursuant to which, among other things, Memorial Resource performs all operational, management and administrative services on our general partner’s and our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocated to us, including expenses incurred by our general partner and its affiliates on our behalf. Memorial Resource allocates its indirect general and administrative costs based on estimated time spent on each entity, which it believes accurately reflects the costs incurred to provide services to us. Under our partnership agreement and the omnibus agreement, we reimburse Memorial Resource for all direct and indirect costs incurred on our behalf. For a detailed description of the omnibus agreement, please read “Item 13. Certain Relationships and Related Transactions, and Director Independence - Related Party Agreements - Omnibus Agreement.”
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Interest expense. We finance a portion of our working capital requirements, capital development and acquisitions with borrowings under our revolving credit facility and senior note issuances. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and financing decisions. We expect to continue to incur significant interest expense.
Adjusted EBITDA
We include in this report the non-GAAP financial measure Adjusted EBITDA and provide our calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net cash flow from operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income (loss):
Plus:
·
Interest expense, including gains or losses on interest rate derivative contracts;
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Income tax expense;
·
Depreciation, depletion and amortization (“DD&A”);
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Impairment of goodwill and long-lived assets (including oil and natural gas properties);
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Accretion of asset retirement obligations (“AROs”);
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Loss on commodity derivative instruments;
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Cash settlements received on expired commodity derivative instruments;
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Losses on sale of assets and other, net;
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Unit-based compensation expenses;
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Exploration costs;
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Acquisition related costs; and
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Other non-routine items that we deem appropriate.
Less:
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Interest income;
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Income tax benefit;
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Gain on expired commodity derivative instruments;
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Cash settlements paid on expired commodity derivative instruments;
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Gains on sale of assets and other, net; and
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Other non-routine items that we deem appropriate.
We are required to comply with certain Adjusted EBITDA-related metrics under our revolving credit facility.
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:
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our operating performance as compared to that of other companies and partnerships in our industry, without regard to financing methods, capital structure or historical cost basis;
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the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make distributions on our units; and
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the viability of projects and the overall rates of return on alternative investment opportunities.
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 flow 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.
The following tables present our calculation of Adjusted EBITDA as well as a reconciliation of Adjusted EBITDA to cash flows from operating activities, our most directly comparable GAAP financial measure, for each of the periods indicated.
Calculation of Adjusted EBITDA
Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA
Outlook
Our financial position and future prospects, including our revenues, operating results, profitability, liquidity, future growth and the value of our assets, depend primarily on prevailing commodity prices. Starting in 2014, throughout 2015 and continuing into 2016, commodity prices dropped significantly, with the West Texas Intermediate posted price declining from $107 per Bbl in June 2014 to less than $30 per Bbl in January 2016 and the Henry Hub spot market price declining from $6 per MMBtu in February 2014 to less than $3 per MMBtu in January 2016. NGL prices have also suffered significant declines. A combination of oversupply from production growth and weaker demand has contributed to the falling prices. In light of the foregoing, projected capital spending and drilling programs by exploration and production companies are expected to dramatically decline.
As a result of the significant decline in commodity prices and general uncertainty regarding the timing and nature of the recovery of prices in the future, we expect 2016 to be challenging and our strategic focus will be on reducing our operating costs and seeking to preserve as much of our liquidity and financial flexibility as possible in this lower commodity price environment.
Given the uncertainty regarding the timing and magnitude of an eventual recovery of commodity prices, we have reduced planned capital spending in 2016 by approximately 67% compared to 2015 levels. In 2016, we plan to focus our capital expenditures on required maintenance across our properties, spending approximately 38% of our capital budget in East Texas, 27% in California, 20% in the Rockies and the balance in the Eagle Ford, conventional South Texas and the Permian Basin.
Our proved reserves and production decline continually over time. If our capital program continues to be limited or is further reduced in the future, our reserves, production volumes and cash flows from operations are expected to be lower. With our current capital program, we expect our 2016 production to decline about 7% from 2015 levels. Although we believe our currently reduced capital spending will allow us to maintain production levels relatively flat for some time, we can do this for only so long before our production will likely begin to decline significantly, which would further lower our cash flow from operations. And while accretive acquisitions are also a key component of our business strategy of maintaining and growing a stable production profile because we own a limited amount of undeveloped properties, as a result of the effect of weakened commodity prices on the price of our equity and debt securities, we may be limited in our ability to access the capital markets at an acceptable cost or at all; thus our ability to make any acquisitions may be limited. Based on the current environment and the economics of producing oil and natural gas from our properties, we believe it is prudent to focus on our liquidity and financial flexibility.
If the borrowing base under our revolving credit facility is reduced further because of lower commodity prices and we are otherwise unable to maintain our current liquidity position, we may no longer have the financial flexibility to manage our business, including, among other things, funding our planned capital expenditures or making distributions to our unitholders. For a discussion of restrictions under our revolving credit facility, please read “Item 1A. Risk Factors - The terms of our indebtedness include restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.”
For a discussion of potential future impairments, please read “Item 1A. Risk Factors - If commodity prices decline further and remain depressed for a prolonged period, a significant portion of our development projects may become uneconomic and cause further write downs of the value of our oil and natural gas properties, which may adversely affect our financial condition and our ability to make distributions to our unitholders.”
As of December 31, 2015, based on our reserve report, future development costs relating to the development of our PUDs for the years 2016 through 2020 are estimated at approximately $725 million to capture the balance of drilling the PUD reserves within a five-year timeframe, of which $80 million is for 2016. The rate at which we develop our PUD reserves may vary from year to year. As we have done historically, we may adjust our capital expenditures budget throughout the year as circumstances warrant to respond to changes in commodity prices and other economic conditions. Despite a reduced capital budget in 2016 that is reflective of the current price environment, we believe that we can fund the drilling of our current inventory of PUD locations and our expansions in the next five years from our cash flow from operations (inclusive of realized derivative contract gains and losses), and, if needed, our revolving credit facility. The development of our PUD reserves is further discussed under “Item 1. Business - Our Oil and Natural Gas Data - Development of Proved Undeveloped Reserves.”
For a discussion of the potential impact of commodity price changes on our estimated proved reserve, including quantification of such potential impact, please read “Item 1. Business - Our Oil and Natural Gas Data - Reserves Sensitivity.”
Commodity prices have historically been volatile, and we expect this volatility to continue for the foreseeable future. We will continue to monitor our liquidity, including opportunities for liquidity enhancement through possible divestitures and joint-venture arrangements, coordinate our capital expenditure program with our expected cash flows and projected debt-repayment schedule, and evaluate available funding and other strategic alternatives in light of the current and expected commodity price environment and market conditions.
Critical Accounting Policies and Estimates
Oil and Natural Gas Properties
We use the successful efforts method of accounting to account for our oil and natural gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred.
As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and natural gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves.
On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and any gain or loss is recognized.
Proved Oil and Natural Gas Reserves
The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the FASB. These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. We intend to have our internally prepared reserve report as of December 31 of each year audited by independent reserve engineers for a vast majority of our proved reserves and to prepare internal estimates of our proved reserves as of June 30 of each year.
Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.
A decline in proved reserves may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of oil and gas producing properties for impairment.
Impairments
Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates, less than expected production or drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the net carrying value of the property to determine if the carrying amount is recoverable. If the net carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.
Asset Retirement Obligations
An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability.
Derivative Instruments
Commodity derivative financial instruments (e.g., swaps, floors, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under credit facilities. Every derivative instrument is recorded in the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized currently in earnings as we have not elected hedge accounting for any of our derivative positions.
Results of Operations
The results of operations for the years ended December 31, 2015, 2014, and 2013 have been derived from both our consolidated financial statements and our previous owners’ combined financial statements. The previous owners combined financial statements reflect: (i) the WHT Properties through the date of acquisition, (ii) the financial statements of the Cinco Group on a combined basis for periods after common control commenced through the date of acquisition, and (iii) certain oil and gas properties primarily located in East Texas and Louisiana acquired from Memorial Resource in February 2015 for periods after common control commenced through the date of acquisition. 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 operated separately during those periods.
Factors Affecting the Comparability of the Combined Historical Financial Results
The comparability of the results of operations among the periods presented is impacted by the following significant transactions:
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The acquisition of the remaining interest in the Beta properties from a third party in November 2015 for approximately $94.6 million.
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The acquisition of certain oil and natural gas liquids properties in Wyoming from a third party in July 2014 for a purchase price of approximately $906.1 million.
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The acquisition of certain oil and natural gas producing properties in the Eagle Ford from a third party in March 2014 for a total purchase price of approximately $168.1 million.
As a result of the factors listed above, the combined historical results of operations and period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results.
The table below summarizes certain of the results of operations and period-to-period comparisons for the periods indicated.
Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
A net loss of $395.5 million was recorded for the year ended December 31, 2015, primarily due to impairment charges partially offset by significant gains on commodity derivatives. Net income of $115.6 million was generated for the year ended December 31, 2014, primarily due to significant gains on commodity derivatives which were partially offset by impairment charges.
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Oil, natural gas and NGL revenues for 2015 totaled $355.4 million, a decrease of $206.3 million compared with 2014. Production increased 9.8 Bcfe (approximately 12%), primarily from increased drilling activities and volumes from third party acquisitions. The average realized sales price decreased $2.96 per Mcfe primarily due to lower period-to-period commodity prices. The favorable volume and unfavorable pricing variance contributed to an approximate $66.6 million increase and $272.9 million decrease in revenues, respectively.
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Lease operating expenses were $168.2 million and $143.7 million for 2015 and 2014, respectively. In our July 2014 Wyoming acquisition, we acquired oil properties, which are generally more expensive to operate compared to natural gas properties (on a per Mcfe basis). On a per Mcfe basis, lease operating expenses increased to $1.82 for 2015 from $1.74 for 2014 due to 2014 oil acquisitions.
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Gathering, processing and transportation expenses were $34.9 million and $31.9 million for 2015 and 2014, respectively. On a per Mcfe basis, gathering, processing and transportation expenses were $0.38 for 2015 compared to $0.39 for 2014.
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Taxes other than income for 2015 totaled $25.8 million, a decrease of $7.3 million compared with 2014 primarily due to a decrease in commodity prices. On a per Mcfe basis, these taxes declined to $0.28 per Mcfe for 2015 from $0.40 per Mcfe for 2014 due to a decrease in commodity prices.
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DD&A expense for 2015 was $195.8 million compared to $186.0 million for 2014, a $9.8 million increase primarily due to increased production volumes related to third party acquisitions and our drilling program. Increased production volumes caused DD&A expense to increase by approximately $22.0 million and the change in the DD&A rate between periods caused DD&A expense to decrease by approximately $12.2 million.
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We recognized $616.8 million of impairments during 2015 primarily related to certain properties in East Texas, South Texas, the Permian Basin, Wyoming and Colorado. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily due to declining commodity prices. We recognized $407.5 million of impairments during 2014 primarily related to certain properties in the Permian Basin, East Texas and South Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable due to a downward revision of estimated proved reserves as a result of declining commodity prices and updated well performance data. For additional information, see Note 4 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”
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General and administrative expenses for 2015 were $56.7 million, which included $10.8 million of non-cash unit-based compensation expense, $1.9 million of acquisition-related costs and a $0.8 million loss on a previous corporate office lease. General and administrative expenses for 2014 totaled $49.1 million, which included $7.9 million of non-cash unit-based compensation expense, $4.4 million of acquisition-related costs and a $1.8 million allocated loss on a previous corporate office lease. Payments under the omnibus agreement increased by $7.9 million for 2015 compared to 2014. For additional information, see Note 12 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”
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Net gains on commodity derivative instruments of $462.9 million were recognized during 2015, consisting of $254.0 million of cash settlements received on expired positions, and a $208.9 million increase in the fair value of open positions. Net gains on commodity derivative instruments of $492.3 million were recognized during 2014, consisting of $13.6 million of cash settlements received in addition to a $478.7 million increase in the fair value of open positions.
Given the volatility of commodity prices, it is not possible to predict future reported unrealized mark-to-market net gains or losses and the actual net gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If commodity prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower oil, natural gas and NGL prices. However, if commodity prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher oil, natural gas and NGL prices and will, in this context, be viewed as having resulted in an opportunity cost.
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Interest expense, net totaled $114.7 million during 2015, including amortization of deferred financing fees of approximately $6.1 million and accretion of net discount associated with our senior notes of $2.4 million. Interest expense, net totaled $83.6 million during 2014, including amortization of deferred financing fees of approximately $4.2 million and accretion of net discount associated with our senior notes of $1.9 million. The $31.1 million increase in interest expense is primarily due to a higher aggregate principal amount of our senior notes issued and outstanding during 2015 compared to 2014. Average outstanding borrowings under the Partnership’s revolving credit facility were $652.2 million during 2015 compared to $413.6 million during 2014. For 2015, the Partnership had an average of $1.2 billion aggregate principal amount of our senior notes issued and outstanding. For 2014, the Partnership had an average of $950.7 million aggregate principal amount of our senior notes issued and outstanding.
Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013
Net income of $115.6 million was generated for 2014, primarily due to significant gains on commodity derivatives which were mostly offset by impairment charges. Net income was $61.0 million for 2013, of which $52.0 million was attributable to the previous owners.
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Oil, natural gas and NGL revenues for 2014 totaled $561.7 million, an increase of $170.2 million compared with 2013. Production increased 19.6 Bcfe (approximately 31%), primarily from volumes associated with third party acquisitions. The average realized sales price increased $0.59 per Mcfe primarily due to an increase in oil volumes relative to other commodities related to our acquisitions in 2014. The favorable volume and pricing variance contributed to an approximate $122.0 million and $48.2 million increase in revenues, respectively.
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Lease operating expenses were $143.7 million and $94.6 million for 2014 and 2013, respectively. In our July 2014 Wyoming acquisition, we acquired oil properties which are generally more expensive to operate compared to natural gas properties (on a per Mcfe basis). On a per Mcfe basis, lease operating expenses increased to $1.74 for 2014 from $1.50 for 2013 due to 2014 oil acquisitions.
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Gathering, processing and transportation expenses were $31.9 million and $25.1 million for 2014 and 2013, respectively. On a per Mcfe basis, gathering, processing and transportation expenses were $0.39 for 2014 compared to $0.40 for 2013.
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Taxes other than income for 2014 totaled $33.1 million, an increase of $14.7 million compared with 2013 primarily due to an increase in production volumes and ad valorem tax rates. On a per Mcfe basis, production and ad valorem taxes increased to $0.40 per Mcfe for 2014 from $0.29 per Mcfe for 2013 due to higher production tax rates on a per Mcfe basis for production from our Wyoming properties.
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DD&A expense for 2014 was $186.0 million compared to $113.8 million for 2013, a $72.2 million increase primarily due to both an increase in the depletable cost base and increased production volumes related to third party acquisitions and the Partnership’s drilling program. Increased production volumes caused DD&A expense to increase by an approximate $35.5 million and the change in the DD&A rate between periods caused DD&A expense to increase by approximately $36.7 million.
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We recognized $407.5 million of impairments during 2014 primarily related to certain properties in the Permian Basin, East Texas and South Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable due to a downward revision of estimated proved reserves as a result of declining commodity prices and updated well performance data. We recorded $4.1 million of impairments during 2013 related to certain properties in South Texas. In South Texas, the estimated future cash flows expected these properties were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on pricing terms specific to these properties. For additional information, see Note 4 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”
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General and administrative expenses for 2014 were $49.1 million. General and administrative expenses for 2014 included $7.9 million of non-cash unit-based compensation expense, $4.4 million of acquisition-related costs and a $1.8 million allocated loss on a previous corporate office lease. General and administrative expenses for 2013 totaled $54.9 million, of which $26.2 million was attributable to the previous owners. General and administrative expenses for 2013 included $3.6 million of non-cash unit-based compensation expense and $6.7 million of acquisition-related costs. The $5.8 million decrease in general and administrative expenses consisted of $5.8 million of one-time compensation expense related to the Tanos management buyout and approximately $8.3 million of one-time compensation expense related to the Classic management buyout during 2013 offset by increased salaries and employee count between periods.
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Net gains on commodity derivative instruments of $492.3 million were recognized during 2014, consisting of $13.6 million of cash settlements received in addition to a $478.7 million increase in the fair value of open positions. Net gains on commodity derivative instruments of $26.1 million were recognized during 2013, of which $23.6 million consisted of cash settlements received.
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Interest expense, net totaled $83.6 million during 2014, including amortization of deferred financing fees of approximately $4.2 million and accretion of net discount associated with our senior notes of $1.9 million. Interest expense, net totaled $44.3 million during 2013, including gains on interest rate swaps of approximately $1.5 million, amortization of deferred financing fees of approximately $6.0 million (including write-offs associated with the previous owner’s revolving credit facility at the time their debt was repaid and terminated in March 2013) and accretion of net discount associated with our senior notes of $0.5 million. The $39.2 million increase in interest expense is primarily due to a higher aggregate principal amount of our senior notes issued and outstanding for during 2014 compared to 2013.
Average outstanding borrowings under the Partnership’s revolving credit facility were $413.6 million during 2014 compared to $184.7 million during 2013. Average outstanding borrowings under the previous owners’ revolving credit facilities were $101.3 million during 2013, which included $80.0 million in borrowings related to Classic. For 2014, the Partnership had an average of $950.7 million aggregate principal amount of our senior notes issued and outstanding. For 2013, the Partnership had an average of $342.2 million aggregate principal amount of our senior notes issued and outstanding.
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. In 2016, we expect our funding sources to be cash flows generated by operating activities, available borrowing capacity under our revolving credit facility, access to debt and equity capital markets, and/or divestitures of non-core assets. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements.
If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures, reduce distributions to unitholders, and/or fund a portion of our capital expenditures using borrowings under our revolving credit facility, issuances of debt and equity securities or from other sources, such as asset divestitures. Needed capital may not be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by many factors, including the covenants in our revolving credit facility or our indentures. If we are unable to obtain funds when needed or on acceptable terms, we may be unable to finance the capital expenditures necessary to maintain our production or proved reserves.
Revolving Credit Facility. As of December 31, 2015, we had approximately $336.9 million of available borrowing capacity under our revolving credit facility, which is net of $2.1 million in letters of credit. We had $0.6 million of cash and cash equivalents as of December 31, 2015. As of December 31, 2015, the borrowing base under our revolving credit facility was $1.175 billion and we had $836.0 million of outstanding borrowings. The borrowing base under our revolving credit facility is subject to redetermination on at least a semi-annual basis primarily based on an engineering report with respect to our estimated oil, NGL, and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. The next borrowing base redetermination is expected to become effective in April 2016 and will likely result in the lowering of our borrowing base. A continuing decline in oil and natural gas prices or a prolonged period of lower oil and natural gas prices could result in a further reduction of our borrowing base under our revolving credit facility and could trigger mandatory principal repayments. Further, in connection with any reduction of the borrowing base in this lower commodity price environment, we may be required to amend our revolving credit facility, which although the substance of such amendment is currently unknown, would likely reduce the financial flexibility we currently have.
Capital Markets. We may have the ability to issue additional equity and debt as needed through public or private offerings of such securities. 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. We have also filed a shelf registration statement with the SEC which will allow us to issue our common units from time to time potentially through an “at the market” equity program in the future at prices and terms to be determined by market conditions and other factors. Our access to capital markets is affected by the price and performance of our equity and debt securities and commodity prices, which impact capital market conditions for all oil and gas exploration and production companies.
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. See “Item 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
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 oil and natural gas 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 oil and natural gas production through various transactions that fix the future prices received. It has been our practice to enter into costless collars and fixed price swaps only with lenders under our credit agreement. Historically, the Partnership has not paid or received premiums for options. In February 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 the crude oil derivatives were applied as premiums for the new NGL derivatives. In November 2015, we had cash settlement receipts of $16.5 million from the termination of certain WTI crude oil derivatives that were applied as premiums for new Brent crude oil derivatives. As a part of our 2015 Beta Acquisition, we acquired crude oil derivatives. These derivatives were immediately restructured by terminating “in-the-money” crude oil derivatives settling in 2015 through 2016 and entering into new crude oil derivatives. Cash settlement receipts of approximately $4.4 million from the termination of the crude oil derivatives were applied as premiums for the new crude oil swaps.
Swaps. In a typical commodity swap agreement, we receive the difference between a fixed price per unit of production and a price based on an agreed upon published third-party index, if the index price is lower than the fixed price. If the index price is higher, we pay the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our swaps are settled in cash on a monthly basis.
Basis Swaps. These instruments are arrangements that guarantee a price differential to either NYMEX for natural gas or ICE Brent for oil from a specified delivery point. Our basis protection swaps typically have negative differentials to either NYMEX or ICE. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and we pay the counterparty if the price differential is less than the stated terms of the contract.
Collars. In a typical collar arrangement, we receive the excess, if any, of the contract floor price over the reference price, based on NYMEX, ICE, or regional quoted prices, and pay the excess, if any, of the reference price over the contract ceiling price. Collars are typically exercised in cash on a monthly basis only when the reference price is outside of floor and ceiling prices (the collar), otherwise they expire. As of December 31, 2015, we did not have any outstanding collars.
The following table summarizes our derivative contracts as of December 31, 2015 and the average prices at which the production will be hedged:
Our basis swaps as of December 31, 2015 included in the table above are presented on a disaggregated basis below:
The following table summarizes our derivative contracts as of December 31, 2014 and the average prices at which the production was hedged:
(1)
These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps.
Our basis swaps as of December 31, 2014 included in the table above are presented on a disaggregated basis below:
The change in volumes between the current and preceding fiscal year is primarily due to acquisitions and new drilling activity during 2015.
Interest Rate Risk
At December 31, 2015, we had $836.0 million of debt outstanding under our revolving credit facility, with a LIBOR Market Index Rate plus 2.00%, or 2.43%. 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.
Periodically, interest rate swaps are entered into to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. At December 31, 2015, we had the following interest rate swap open positions:
(1)
Weighted-average fixed rate does not include the margin that varies from 0.50% to 2.5% per annum according to the borrowing base usage and type of borrowing.
At December 31, 2014, we had the following interest rate open swap positions:
(1)
Weighted-average fixed rate does not include the margin that varies from 0.50% to 2.5% per annum according to the borrowing base usage and type of borrowing.
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 issue costs and any discount or premium) is compared to the estimated fair value in the table below (in thousands):
Counterparty and Customer Credit Risk
Joint interest billings receivable represent amounts receivable for lease operating expenses and other costs due from third party working interest owners in the wells that the Partnership operates. The receivable is recognized when the cost is incurred. We have limited ability to control participation in our wells. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. See “Item 1. Business” for further detail about our significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our derivative contracts may expose us to credit risk in the event of nonperformance by counterparties. As of December 31, 2015, some of the lenders, or certain of their affiliates, under our revolving credit facility 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. 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 December 31, 2015, after taking into effect netting arrangements, we had counterparty exposure of $380.9 million related to our derivative instruments. As a result, had certain counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $350.0 million against amounts outstanding under our revolving credit facility at December 31, 2015.
While we do not require our customers to post collateral and do not have a formal process in place to evaluate and assess the credit standing of our significant customers or the counterparties on our derivative contracts, we do evaluate the credit standing of our customers and such counterparties as we deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’s credit rating and latest financial information or, in the case of a customer with which we have receivables, reviewing its historical payment record, the financial ability of the customer’s parent company to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. Some of the counterparties on our derivative contracts in place as of December 31, 2015 are lenders under our revolving credit facility with investment grade ratings, and we are likely to enter into any future derivative contracts with these or other lenders under our revolving credit facility that also carry investment grade ratings. Several of our significant customers for oil and natural gas receivables have a credit rating below investment grade or do not have rated debt securities. In these circumstances, we have considered the lack of investment grade credit rating in addition to the other factors described above.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our Consolidated and Combined Financial Statements, together with the report of our independent registered public accounting firm begin on page of this annual report.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures.
As required by Rules 13a-15(b) and 15d-15(b) of 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 annual 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 December 31, 2015.
Management’s Report on Internal Control Over Financial Reporting
The Partnership’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting, no matter how well designed, has inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Under the supervision and with the participation of the Partnership’s management, including the principal executive officer and principal financial officer of our general partner, the Partnership assessed the effectiveness of its internal control over financial reporting based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this assessment, the Partnership’s management, including our general partner’s principal executive and financial officers, concluded that the Partnership’s internal control over financial reporting was effective as of December 31, 2015 based on the criteria set forth under the COSO Framework.
KPMG LLP, the independent registered public accounting firm who audited the Partnership’s consolidated and combined financial statements included under “Item 8. Financial Statements and Supplementary Data” in this annual report, has issued an attestation report on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2015. The report, which expresses an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2015, is contained herein under the heading “Report of Independent Registered Public Accounting Firm.”
Changes in Internal Controls Over Financial Reporting
No changes in our internal control over financial reporting occurred during the quarter ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
The certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 are filed as exhibits 31.1 and 31.2, respectively, to this annual report.
Report of Independent Registered Public Accounting Firm
The Board of Directors of Memorial Production Partners GP LLC and
Unitholders of Memorial Production Partners LP:
We have audited Memorial Production Partners LP and subsidiaries’ (the Partnership) internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Report on Internal Control over Financial Reporting in Item 9A of Form 10-K. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Memorial Production Partners LP and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Memorial Production Partners LP and subsidiaries as of December 31, 2015, the consolidated and combined balance sheet of Memorial Production Partners LP as of December 31, 2014, and the related consolidated and combined statements of operations, equity, and cash flows for each of the years in the three-year period ended December 31, 2015, and our report dated February 24, 2016 expressed an unqualified opinion on those consolidated and combined financial statements.
/s/ KPMG LLP
Houston, Texas
February 24, 2016
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Management
Memorial Production Partners GP LLC, our general partner, manages our operations and activities on our behalf. Our general partner is a wholly-owned subsidiary of Memorial Resource. All of our executive management personnel are employees of Memorial Resource and devote their time as needed to conduct our business and affairs.
Our general partner has a board of directors that oversees its management, operations and activities. The board of directors currently has seven members. The board of directors has determined that Messrs. Clarkson, Highum and Brunson satisfy the independence standards established by NASDAQ and SEC rules. Because we are a limited partnership, we are not required to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee.
Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders will not be entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Memorial Resource appoints all members to the board of directors of our general partner.
Our general partner owes a contractual duty to our unitholders that is defined by our partnership agreement. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, our general partner intends to cause us to incur indebtedness or other obligations that are nonrecourse to it. Except for limited circumstances under our partnership agreement and subject to its duty under our partnership agreement to act in good faith, our general partner has exclusive management power over our business and affairs.
Board Leadership Structure and Role in Risk Oversight
Leadership of our general partner’s board of directors is vested in a Chairman of the board. John A. Weinzierl serves as the Chairman of the board of directors of our general partner and as Chief Executive Officer of our general partner. Our general partner’s board of directors has determined that the combined roles of Chairman and Chief Executive Officer allows the board of directors to take advantage of the leadership skills of Mr. Weinzierl and is appropriate because Mr. Weinzierl works closely with our management team on a daily basis and is in the most knowledgeable position to determine the timing for board meetings and propose agendas for meetings. However, any director can suggest agenda items for a board meeting. Mr. Weinzierl’s in-depth knowledge of, and experience in, our business, history, structure and organization facilitates timely communications between our general partner’s management and the board of directors. Our general partner’s board of directors has also determined that having the Chief Executive Officer serve as a director enhances understanding and communication between management and the board of directors, allows for better comprehension and evaluation of our operations and ultimately improves the ability of the board of directors to perform its oversight role. In addition, our general partner’s board of directors believes that maintaining the combined Chairman and Chief Executive Officer positions contributes to a consistent strategy and direction for us and our unitholders by alleviating potential ambiguities in the decision-making process.
The management of enterprise-level risk may be defined as the process of identifying, managing and monitoring events that present opportunities and risks with respect to the creation of value for our unitholders. The board of directors of our general partner has delegated to management the primary responsibility for enterprise-level risk management, while the board of directors has retained responsibility for oversight of management in that regard. Our executive officers offer an enterprise-level risk assessment to the board of directors at least once every year.
Directors and Executive Officers
The following table sets forth certain information regarding the current directors and executive officers of our general partner as of February 24, 2016.
Our general partner’s directors hold office until the earlier of their respective death, resignation, removal or disqualification or until their respective successors have been elected and qualified. Officers serve at the discretion of the board of directors. In selecting and appointing directors to the board of directors, the owners of our general partner do not intend to apply a formal diversity policy or set of guidelines. However, when appointing new directors, the owners of our general partner will consider each individual director’s qualifications, skills, business experience and capacity to serve as a director, as described below for each director, and the diversity of these attributes for the board of directors as a whole.
John A. Weinzierl has served as our general partner’s Chief Executive Officer and Chairman of the board of directors since January 2014. Previously, Mr. Weinzierl served as our general partner’s President, Chief Executive Officer and Chairman of the board from April 2011 to January 2014. Mr. Weinzierl also served as Chief Executive Officer and a director of Memorial Resource from January 2014 to January 2016. Previously, Mr. Weinzierl served as President and Chief Executive Officer of MRD LLC from April 2011 to January 2014 and then as Chief Executive Officer until June 2014. Prior to the completion of our initial public offering in December 2011, Mr. Weinzierl was a managing director and operating partner of NGP from December 2010. From July 1999 to December 2010, Mr. Weinzierl worked in various positions at NGP, where he became a managing director in December 2004. Mr. Weinzierl was appointed a venture partner of NGP from February 2012 to February 2013. From October 2006 until November 2011, Mr. Weinzierl was a director of Eagle Rock Energy G&P, LLC, the indirect general partner of Eagle Rock Energy Partners, L.P., a (i) natural gas gathering, processing and transportation company and (ii) developer of oil and natural gas properties, where he also served on the compensation committee. Mr. Weinzierl is a registered professional engineer in Texas.
The board believes Mr. Weinzierl’s degree and experience in petroleum engineering, his M.B.A. education, as well as his investment and business expertise honed at NGP brings valuable strategic, managerial and analytical skills to the board and us.
William J. Scarff has served as our general partner’s President since January 2014. Mr. Scarff also served as President of Memorial Resource from January 2014 to January 2016. Previously, Mr. Scarff served as President of MRD LLC from January 2014 to June 2014. From 2000 through January 2014, Mr. Scarff has served as President and Chief Executive Officer of several private exploration and production companies sponsored by NGP. From October 2010 until January 2014, Mr. Scarff was President and Chief Executive Officer of Propel Energy, LLC. Prior to that, he was President and Chief Executive Officer of Seismic Ventures, Inc. from 2006 to 2009. From 2005 to 2014, Mr. Scarff was President and Chief Executive Officer of Proton Operating Company, LLC and from 1999 to 2005, he was President and Chief Executive Officer of Proton Energy, LLC and its affiliates. From 1978 to 1999, Mr. Scarff held a variety of positions of increasing responsibility in Marathon Oil Company, Anadarko Production Company, Burlington Resources, Texas Meridian Resource Corporation and Hilcorp Energy Company.
Robert L. Stillwell, Jr. has served as our general partner’s Vice President and Chief Financial Officer since January 2015 and was Vice President, Finance from July 2014 through December 2014. Previously, he served as Treasurer of MRD LLC from June 2012 to June 2014. From January 2011 to June 2012, Mr. Stillwell served as an investment banker at Citigroup in the Global Energy Group. From June 2010 to December 2010 and from July 2007 to June 2010, he worked in investment banking with UBS and Scotia Waterous, respectively. Mr. Stillwell began his career in the corporate finance group of EXCO Resources, Inc.
Christopher S. Cooper has served as our general partner’s Senior Vice President and Chief Operating Officer since November 2014. Previously, he served in a variety of operational, technical and strategic planning positions with Marathon Oil Company since 1990. From August 2013 until November 2014, Mr. Cooper served as Director, Global Projects. From November 2011 until August 2013, he served as Director, Financial Planning/Operations. From July 2009 until November 2011, Mr. Cooper served as Asset Manager/Regional Vice President, Mid-Continent, and from May 2007 until July 2009, he served as Asset Manager, Powder River Basin.
Kyle N. Roane has served as our general partner’s Senior Vice President, Compliance and Administration since July 2015. Previously, he served as our general partner’s Senior Vice President, General Counsel and Corporate Secretary from November 2014 to July 2015 and our Vice President, General Counsel and Corporate Secretary from January 2014 to November 2014. Previously, he served as our general partner’s General Counsel and Corporate Secretary from February 2012 through December 2013. Mr. Roane has also served as Senior Vice President, General Counsel and Corporate Secretary of Memorial Resource since November 2014 and was Vice President, General Counsel and Corporate Secretary from January 2014 to November 2014. Previously, Mr. Roane served as Vice President, General Counsel and Corporate Secretary of MRD LLC from January 2014 to June 2014 and was General Counsel and Corporate Secretary of MRD LLC from February 2012 through December 2013. From 2005 to February 2012, Mr. Roane practiced corporate and securities law at Akin, Gump, Strauss, Hauer & Feld L.L.P.
Gregory M. Robbins has served as our general partner’s Senior Vice President, Corporate Development since November 2014 and Vice President, Corporate Development from January 2013 to November 2014. Previously, he served as our general partner’s Treasurer from June 2011 to April 2012 and Director of Corporate Development from April 2012 to January 2013. Mr. Robbins has also served as Senior Vice President, Corporate Development of Memorial Resource since November 2014 and was Vice President, Corporate Development from April 2014 to November 2014. Previously, Mr. Robbins served as the Vice President of Corporate Development of MRD LLC from January 2013 to June 2014, Director of Corporate Development from April 2012 to January 2013, and Treasurer from June 2011 to April 2012. From October 2010 to April 2011, Mr. Robbins served as Vice President and Controller of Quality Electric Steel Castings, LP. Prior to that, he was a Vice President with Guggenheim Partners, LLC from April 2006 to September 2010. Mr. Robbins worked for Wells Fargo Energy Capital, LLC from 2004 to March 2006 and Comerica Bank, Inc. from 2002 to 2004.
Dennis G. Venghaus has served as our general partner’s Vice President and Chief Accounting Officer since October 2015. Since January 2015, Mr. Venghaus has also served as Memorial Resource’s Vice President and Chief Accounting Officer and its Chief Accounting Officer since its formation. Previously, he served as the Controller of MRD LLC from January 2012 to June 2014 and our general partner from January 2012 to October 2015. Mr. Venghaus was with Opportune LLP from June 2010 to January 2012 as a Manager in the Complex Financial Reporting group. From September 2004 through June 2010, he held various positions in the audit practice at PricewaterhouseCoopers LLP in Houston, Texas, primarily serving energy clients. Mr. Venghaus is a Certified Public Accountant.
Jason M. Childress has served as our general partner’s Vice President, General Counsel and Corporate Secretary since July 2015. Mr. Childress has served as the Assistant General Counsel and Assistant Secretary of Memorial Resource since January 2014 and the Assistant General Counsel of MRD LLC from January 2013 to June 2014. From 2007 to January 2013, Mr. Childress practiced corporate and securities law at Akin, Gump, Strauss, Hauer & Feld L.L.P. Prior to that, he held various positions in the audit practice at PricewaterhouseCoopers LLP.
W. Donald Brunson has served as a member of the board of directors of our general partner since December 2014. Subsequent to his retirement in 2012, Mr. Brunson has served as Chairman and Co-Founder of Bank of Houston from 2004 to 2012. From 2012 to 2014, he served as Chairman Emeritus of Bank of Houston. From 1996 to 2004, he held positions with American Prudential Capital, Inc. In 1994 and 1995, he served as President and was a board member and member of the executive management committee with Sunbelt National Bank. Prior to 1994, Mr. Brunson also held positions with Southwest Bank of Texas, Heights State Bank, Houston National Bank, Allied Bank of Texas, and Price Waterhouse & Co.
The board believes that Mr. Brunson’s extensive banking experience brings substantial and valuable skills and experiences to the board of directors.
Jonathan M. Clarkson has served as a member of the board of directors of our general partner since December 2011. Mr. Clarkson recently retired as Chief Financial Officer for Matrix Oil Corporation effective January 1, 2016. He had served in that capacity since May 2012. Mr. Clarkson served as Chairman of the Houston Region of Texas Capital Bank from May 2009 until his retirement in December 2011. From 2003 to May 2009, he served as President and CEO of the Houston Region of Texas Capital Bank. From May 2001 to October 2002, Mr. Clarkson served as President, Chief Financial Officer and a director of Mission Resources Corp., an independent oil and gas exploration and production company. From 1999 through 2001, Mr. Clarkson served as President and Chief Operating Officer of Bargo Energy Company, a private company engaged in the acquisition and exploitation of onshore oil and natural gas properties, which merged with Mission Resources in May 2001. From 1987 to 1999, Mr. Clarkson served as Executive Vice President and Chief Financial Officer for Ocean Energy Corp. and its predecessor company United Meridian Corporation. From October 2006 until December 2009, Mr. Clarkson served on the board of directors, was chairman of the audit committee, and was a member of the compensation committee of Edge Petroleum Corp., an oil and gas exploration and production company. Mr. Clarkson currently serves on the board of directors, is chairman of the audit committee, and is a member of the corporate governance committee, of Parker Drilling Company. This service began in January 2012. Since September 2010, Mr. Clarkson has served on the advisory board of Rivington Capital Advisors, LLC, an investment banking firm focused on upstream energy sector investments.
The board believes that Mr. Clarkson brings to the board his substantial prior financial and executive management expertise including his experience as a chief financial officer in the oil and gas industry and his valuable prior board experience and audit and compensation committee service.
Scott A. Gieselman has served as a member of the board of directors of our general partner since September 2011. Mr. Gieselman has also served as a member of the board of directors of Memorial Resource since its formation in January 2014 and was a member of MRD LLC’s board of managers from September 2011 to June 2014. Mr. Gieselman has been a managing director of NGP since April 2007. Mr. Gieselman has served as a member of the board of directors of Rice Energy Inc. since January 2014. From 1988 to April 2007, Mr. Gieselman worked in various positions in the investment banking energy group of Goldman, Sachs & Co., where he became a partner in 2002.
The board believes that Mr. Gieselman’s considerable financial and energy investment banking experience, as well as his experience on the boards of numerous private energy companies bring important and valuable skills to the board of directors.
Kenneth A. Hersh has served as a member of the board of directors of our general partner since its formation in April 2011. Mr. Hersh has also served as a member of the board of directors of Memorial Resource since its formation in January 2014 and was a member of MRD LLC’s board of managers from April 2011 to June 2014. Mr. Hersh is the Chief Executive Officer of NGP Energy Capital Management and a managing partner of NGP and has served in those or similar capacities since 1989. Mr. Hersh served as a director of NGP Capital Resources Company from November 2004 until September 2014. Mr. Hersh served as a director of Resolute Energy Corporation from September 2009 to March 2012, as a director of Eagle Rock Energy G&P, LLC, the indirect general partner of Eagle Rock Energy Partners, L.P., from March 2006 until June 2011 and Energy Transfer Partners, L.L.C., the indirect general partner of Energy Transfer Partners, L.P., a natural gas gathering and processing and transportation and storage and retail propane company, from February 2004 through December 2009, and served as a director of LE GP, LLC, the general partner of Energy Transfer Equity, L.P., from October 2002 through December 2009. Mr. Hersh currently serves on the Dean’s Council of the Harvard Kennedy School. He also served on the Advisory Council of the Graduate School of Business at Stanford University from 2009 through 2015. He is a Senior Advisor to The Carlyle Group. He is also a member of the Council of Foreign Relations and of the World Economic Forum where he has been a featured speaker at its annual meeting held in Davos, Switzerland.
The board believes that Mr. Hersh brings extensive knowledge to the board and us through his experiences in the energy industry as an investor, involvement in complex energy-related transactions and his position as Chief Executive Officer of NGP Energy Capital Management and co-manager of NGP’s investment portfolio. Mr. Hersh also brings a wealth of industry-specific transactional skills, entrepreneurial ideas and a personal network of public and private capital sources that the board believes will bring us opportunities that we may not otherwise have.
P. Michael Highum has served as a member of the board of directors of our general partner since March 2012. Subsequent to his retirement in 2001, he has been primarily involved in managing his private investments. From 2002 to 2006, Mr. Highum served as an advisor to Fidelity Investments, where he helped establish and develop FIML Natural Resources LLC, an oil and gas exploration and production company. He co-founded HS & Associates in 1978, which was the predecessor to the NYSE-listed HS Resources, Inc., an independent oil and gas exploration and production company (later sold to Kerr McGee Corporation in 2001), where he served as President and Director. From 1995 to 2001, Mr. Highum served as a Director (and President in 1999) of the Colorado Oil and Gas Association. Prior to HS & Associates, Mr. Highum practiced corporate law in the San Francisco office of Pillsbury, Madison & Sutro, LLP.
The board believes that Mr. Highum’s considerable executive management and energy investment experience bring substantial investment management skills to the board of directors.
Tony R. Weber has served as a member of the board of directors of our general partner since September 2011. Mr. Weber has also served as Chairman of the board of directors of Memorial Resource since its formation in January 2014 and was a member of MRD LLC’s board of managers from September 2011 to June 2014. Mr. Weber currently serves as Managing Partner and Chief Operating Officer for NGP. Prior to joining NGP in December 2003, Mr. Weber was the Chief Financial Officer of Merit Energy Company from April 1998 to December 2003. Prior to that, he was Senior Vice President and Manager of Union Bank of California’s Energy Division in Dallas, Texas from 1987 to 1998. In his role at NGP, Mr. Weber serves on numerous private company boards as well as industry groups, IPAA Capital Markets Committee and Dallas Wildcat Committee. He currently serves on the Dean’s Council of the Mays Business School at Texas A&M University and was a founding member of the Mays Business Fellows Program.
The board believes that Mr. Weber’s extensive corporate finance, banking and private equity experience bring substantial leadership skill and experience to the board of directors.
Composition of the Board of Directors
Our general partner’s board of directors consists of seven members. The board of directors holds regular and special meetings at any time as may be necessary. Regular meetings may be held without notice on dates set by the board of directors from time to time. Special meetings of the board of directors or meetings of any committee thereof may be held at the request of the Chairman of the board of directors or a majority of the board of directors (or a majority of the members of such committee) upon at least two days (if the meeting is to be held in person) or 24 hours (if the meeting is to be held telephonically) prior oral or written notice to the other members of the board or committee or upon such shorter notice as may be approved by the directors or members of such committee. A quorum for a regular or special meeting will exist when a majority of the members are participating in the meeting either in person or by telephone conference. Any action required or permitted to be taken at a board meeting may be taken without a meeting if such action is evidenced in writing and signed by all of the members of the board of directors.
Meeting of Non-Management Directors and Communications with Directors
At each quarterly meeting of the board of directors of our general partner, all of our independent directors intend to meet in an executive session without participation by management or non-independent directors. Mr. Clarkson is expected to preside over these executive sessions.
Unitholders or interested parties may communicate directly with the board of directors of our general partner, any committee of the board of directors, any independent directors, or any one director, by sending written correspondence by mail addressed to the board, committee or director to the attention of our Secretary at the following address: c/o Secretary, Memorial Production Partners LP, 500 Dallas Street, Suite 1800, Houston, Texas 77002. Communications are distributed to the board of directors, committee of the board of directors, or director as appropriate, depending on the facts and circumstances outlined in the communication. Commercial solicitations or communications will not be forwarded.
Committees of the Board of Directors
The board of directors established an audit committee and from time to time, establishes a conflicts committee.
Because we are a limited partnership, the listing standards of the NASDAQ do not require that we or our general partner have a majority of independent directors or a nominating or compensation committee of the board of directors. We are, however, required to have an audit committee, whose members are required to be “independent” under NASDAQ standards as described below.
Audit Committee
The board of directors of our general partner has established an audit committee. The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approves all auditing services and related fees and the terms thereof, and pre-approves any non-audit services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee. The charter for the audit committee is available within the “Corporate Governance” section of our website at http://investor.memorialpp.com/governance.cfm. The information contained on, or connected to, our website is not incorporated by reference into this annual report and should not be considered part of this or any other report that we file with or furnish to the SEC.
Messrs. Clarkson, Highum and Brunson currently serve on the audit committee, and Mr. Clarkson serves as the chairman. Messrs. Clarkson, Highum and Brunson meet the independence and experience standards established by NASDAQ and the Securities Exchange Act of 1934, as amended, or the Exchange Act. The board of directors of our general partner has determined that Mr. Clarkson is an “audit committee financial expert” as defined under SEC rules. The audit committee held four meetings in 2015.
Conflicts Committee
From time to time, the board of directors of our general partner will establish a conflicts committee to review specific matters that the board of directors believes may involve conflicts of interest and which it determines to submit to the conflicts committee for review. Under our partnership agreement, the conflicts committee has responsibility for (i) approving the amount of estimated maintenance capital expenditures deducted from operating surplus and (ii) the approval of the allocation of capital expenditures between maintenance capital expenditures, investment capital expenditures and growth capital expenditures. Other than these enumerated responsibilities, our general partner may, but is not required to, seek approval from the conflicts committee regarding a resolution of a conflict of interest with our general partner or affiliates. The conflicts committee may determine the resolution of the conflict of interest. Any matters approved by the conflicts committee will be deemed to be approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.
Every member of the conflicts committee must not be an officer or employee of our general partner or its affiliates, must otherwise be independent of our general partner and its affiliates (including Memorial Resource and NGP), and must meet the independence standards established by the NASDAQ Marketplace Rules and the Exchange Act to serve on an audit committee of a board of directors. We intend for the conflicts committee to generally have at least two members. Because our partnership agreement only requires that the conflicts committee have at least one member, during any time that the committee only has one member, that single member of the conflicts committee will be able to approve resolutions of conflicts of interest. It is possible that a single-member committee may not function as effectively as a multiple-member committee and, if we pursue a transaction with an affiliate while the conflicts committee has only one member, our limited partners will be deemed to have approved that transaction through the approval of that single-member committee, in the same manner as would have occurred had the committee consisted of more directors. The conflicts committee held seven meetings in 2015.
Meetings and Other Information
The board of directors of our general partner held six meetings in 2015.
Our partnership agreement provides that the general partner manages and operates us and that, unlike holders of common stock in a corporation, unitholders only have limited voting rights on matters affecting our business or governance. Accordingly, we do not hold annual meetings of unitholders.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our general partner’s board of directors and officers, and persons who own more than 10% of a class of our equity securities registered pursuant to Section 12 of the Exchange Act, to file reports of beneficial ownership and reports of changes in beneficial ownership of such securities with the SEC. Directors, officers and greater than 10% unitholders are required by SEC regulations to furnish to us copies of all Section 16(a) forms they file with the SEC.
Based solely on a review of the copies of reports on Forms 3, 4 and 5 and amendments thereto furnished to us and written representations from the executive officers and directors of Memorial Production Partners GP LLC, we believe that during the year ended December 31, 2015 the officers and directors of Memorial Production Partners GP LLC and beneficial owners of more than 10% of our equity securities registered pursuant to Section 12 were in compliance with the applicable requirements of Section 16(a).
Corporate Governance
The board of directors of our general partner has adopted a Code of Ethics for Senior Financial Officers, or Code of Ethics, that applies to the chief executive officer, chief financial officer or vice president of finance, chief accounting officer, controller, treasurer and all other persons performing similar functions on behalf of our general partner and us. The board of directors of our general partner has also adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and a Code of Business Conduct and Ethics that applies to the directors, officers and employees of our general partner and its affiliates and us.
We make available free of charge, within the “Corporate Governance” section of our website at http://investor.memorialpp.com/corporate-governance.cfm, and in print to any unitholder who so requests, the Code of Ethics, the Corporate Governance Guidelines and the Code of Business Conduct and Ethics. Requests for print copies may be directed to Investor Relations at ir@memorialpp.com or to Investor Relations, Memorial Production Partners LP, 500 Dallas Street, Suite 1800, Houston, Texas 77002 or made by telephone at (713) 588-8350. We intend to post on our website all waivers of or amendments to the Code of Ethics and Code of Business Conduct and Ethics that are required to be disclosed by applicable law. The information contained on, or connected to, our website is not incorporated by reference into this annual report and should not be considered part of this or any other report that we file with or furnish to the SEC.
Reimbursement of Expenses of Our General Partner
Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates, including Memorial Resource, may be reimbursed.
Pursuant to the omnibus agreement with a wholly-owned subsidiary of Memorial Resource, management, administrative and operational services are provided to our general partner and us to manage and operate our business. Our general partner reimburses Memorial Resource, on a monthly basis, for the allocable expenses it incurs in its performance under the omnibus agreement, and we reimburse our general partner for such payments it makes to Memorial Resource. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated to our general partner. We believe the expenses to be no more than those we would be required to pay if we received services from an unaffiliated third party. Memorial Resource has substantial discretion to determine in good faith which expenses to incur on our behalf and what portion of its expenses to allocate to us. In turn, our partnership agreement provides that our general partner determines in good faith the expenses that are allocable to us. See “Item 13. Certain Relationships and Related Transactions, and Director Independence - Related Party Agreements - Omnibus Agreement.”
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
General
All of our general partner’s executive officers and other personnel necessary for our business to function are employed and compensated by our general partner or Memorial Resource, in each case subject to reimbursement by us. Memorial Resource currently manages our operations and activities, and makes certain compensation decisions on our behalf, under the omnibus agreement. The compensation for all of our general partner’s executive officers is paid by Memorial Resource, and we reimburse Memorial Resource for costs and expenses incurred for our benefit or on our behalf pursuant to the terms of the omnibus agreement. See “Item 13. Certain Relationships and Related Transactions, and Director Independence - Related Party Agreements - Omnibus Agreement” for more information about the omnibus agreement.
Responsibility and authority for compensation-related decisions for executive officers and other personnel employed by our general partner resides with our general partner. Responsibility and authority for compensation-related decisions for executive officers and other personnel that are employed by Memorial Resource reside with Memorial Resource. Our general partner’s executive officers manage our business as part of the service provided by Memorial Resource under the omnibus agreement, and the compensation for all of our general partner’s executive officers is indirectly paid by our general partner through reimbursements to Memorial Resource. All determinations with respect to awards made under our long-term incentive plan to executive officers of our general partner and of Memorial Resource are made by the board of directors of our general partner, following the recommendation of Memorial Resource.
Some of our general partner’s named executive officers are also executive officers of Memorial Resource, and we expect that certain of our general partner’s named executive officers will continue to devote a significant portion of their total business time to Memorial Resource and its operations. Compensation paid or awarded by us with respect to our general partner’s named executive officers reflects only the portion of Memorial Resource’s compensation expense allocated to us by Memorial Resource under the omnibus agreement. Memorial Resource has the ultimate decision-making authority with respect to the total compensation of its employees, including our general partner’s named executive officers, and (subject to the terms of the omnibus agreement) with respect to the portion of that compensation that is allocated to us. Any such compensation decision is not subject to any approval by the board of directors of our general partner.
Our general partner’s “named executive officers” for 2015 were:
Our Compensation Philosophy
Memorial Resource employs a compensation philosophy that emphasizes pay-for-performance (primarily, insofar as it relates to our partnership, the ability to increase sustainable quarterly distributions to unitholders) based on a combination of our partnership’s performance and the individual’s impact on our partnership’s performance and placing the majority of each officer’s compensation at risk. We believe this pay-for-performance approach generally aligns the interests of executive officers who provide services to us with that of our unitholders, and at the same time enables us to maintain a lower level of base salary overhead in the event our operating and financial performance fails to meet expectations. Memorial Resource designs our general partner’s executive compensation to attract and retain individuals with the background and skills necessary to successfully execute our business model in a demanding environment, to motivate those individuals to reach near-term and long-term goals in a way that aligns their interest with that of our unitholders, and to reward success in reaching such goals.
Compensation Setting Process
The portion of our general partner’s named executive officers’ salaries and bonuses incurred by Memorial Resource that was allocated to us, as reflected in the Summary Compensation Table below, was based on, estimated time spent on each entity for 2015 and 2014 and on production for 2013. Memorial Resource has designed a compensation program that emphasizes pay-for-performance. Our general partner’s Chief Executive Officer provides periodic recommendations to Memorial Resource regarding the compensation of our general partner’s other named executive officers.
In the future as part of the compensation setting process, Memorial Resource may: (i) examine the compensation practices of our peer companies, (ii) review compensation information from the oil and gas industry generally to the extent we compete for executive talent from a broader group than our selected peer companies, (iii) review and participate in relevant compensation surveys and (iv) retain compensation consultants.
Elements of Executive Compensation
There are three primary elements of compensation that are used in our general partner’s executive compensation program-base salary, cash bonus and long-term equity incentive awards. Cash bonuses and equity incentives (as opposed to base salary) represent the performance driven elements of the compensation program. They are also flexible in application and can be tailored to meet our objectives. The determination of specific individuals’ cash bonuses will reflect their relative contribution to achieving or exceeding annual goals, and the determination of specific individuals’ long-term incentive awards will be based on their expected contribution in respect of longer term performance objectives. Incentive compensation in respect of services provided to us will not be tied in any material way to the performance of entities other than us and our subsidiaries. Specifically, any performance metrics will not be tied to the performance of Memorial Resource, the Funds or any other NGP affiliate.
Although we bear an allocated portion of the costs of compensation and benefits provided to the Memorial Resource employees who serve as our general partner’s named executive officers, we have no control over such costs, and we will not establish or direct the compensation policies or practices of Memorial Resource. Each of these executive officers continues to perform services for our general partner, as well as for Memorial Resource and its affiliates.
Base Salary. We believe the base salaries for our general partner’s named executive officers are generally competitive within the master limited partnership market, but are moderate relative to base salaries paid by companies with which we compete for similar executive talent across the broad spectrum of the energy industry. We do not expect automatic annual adjustments to be made to base salary. Memorial Resource reviews the base salaries on an annual basis and may make adjustments as necessary to maintain a competitive executive compensation structure. As part of its review, Memorial Resource may examine the compensation of executive officers in similar positions with similar responsibilities at peer companies identified by Memorial Resource or the board of directors of our general partner or at companies within the oil and gas industry with which we generally compete for executive talent.
Bonus Awards. Annual bonus awards are discretionary and determined based on financial and individual performance. Memorial Resource reviews bonus awards for our general partner’s named executive officers annually to determine award payments for the current fiscal year, as well as to establish award opportunities for the next fiscal year. At the end of each fiscal year, Memorial Resource meets with each executive officer to discuss our performance goals for the upcoming fiscal year and what each executive officer is expected to contribute to help us achieve those performance goals. The determination of specific individuals’ cash bonuses will reflect their relative contribution to achieving or exceeding annual goals.
Long Term Incentive Compensation. Our general partner has adopted the Memorial Production Partners GP LLC Long-Term Incentive Plan, or our LTIP, for employees, officers, consultants and directors of our general partner and any of its affiliates, including Memorial Resource, who perform services for us. Each of our general partner’s named executive officers is eligible to participate in our LTIP. Memorial Resource determines the overall amount of all long-term equity incentive compensation to be granted annually for its employees (including the officers of our general partner). The portion of that compensation to be granted under our LTIP will be granted by our general partner’s board of directors following the recommendation of Memorial Resource. Our LTIP is administered by a plan administrator, which is currently the board of directors of our general partner.
Our LTIP allows for the grant of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights (“DERs”), other unit-based awards and unit awards. The purpose of awards under our LTIP is to provide additional incentive compensation to employees providing services to us, and to align the economic interests of such employees with the interests of our unitholders. Our LTIP currently limits the number of common units that may be delivered pursuant to vested awards to 2,142,221 common units. As of December 31, 2015, only 75,194 of those common units remained available for future awards meaning that substantially all authorized and available common units have been issued or have become subject to an outstanding award under the LTIP. Common units cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards.
During the year ended December 31, 2015, our general partner’s named executive officers and independent directors were granted awards of restricted common units as indicated in the following table:
The board of directors of our general partner determines any awards made under our LTIP. With regard to the awards made during 2015, the board of directors took a number of factors into account, including:
·
the financial and operational performance of the Partnership for the year ended December 31, 2014, as well as the period beginning January 1, 2015 through May 2015 (including significant increases in proved reserves, average daily production and Adjusted EBITDA);
·
the significant number of transactions completed by the Partnership and integration of assets acquired in 2014 through May 2015 (including two acquisitions, two public equity offerings, and a debt offering);
·
the rapid and significant growth of the Partnership;
·
the financial and operational performance of the Partnership relative to the performance of other MLPs and other publicly traded oil and gas production companies;
·
the significant demand in Houston and worldwide for experienced oil and gas executives;
·
the significant demand in Houston and elsewhere for experienced MLP executives; and
·
information gathered by the board of directors regarding compensation paid to executives at other MLPs and other public oil and gas production companies.
For any subsequent year, the board of directors may take some or all of these factors into account, and may also consider other factors that it deems relevant at the time of determination.
On January 8, 2016, our general partner’s independent directors were granted additional awards, as indicated in the following table:
The awards were made pursuant to our LTIP and restricted or phantom unit agreements between our general partner and each award recipient. The awards are subject to restrictions on transferability and a substantial risk of forfeiture and are intended to retain and motivate members of our general partner’s management and independent directors. Award recipients have all the rights of a unitholder in us with respect to the restricted units, including the right to receive distributions thereon if and when distributions are made by us to our unitholders. With respect to the phantom units with DERs, the award recipients are entitled to receive a cash payment with respect to each phantom unit equal to any cash distribution made by us to our unitholders. The restricted and phantom units vest and the forfeiture restrictions will generally lapse in substantially equal one-third increments on the first, second, and third anniversaries of the date of grant (except with respect to the awards to our independent directors), so long as the award recipient remains in continuous service with our general partner and its affiliates.
If an award recipient’s service with our general partner or its affiliates is terminated prior to full vesting of the restricted or phantom units for any reason, then the award recipient will forfeit all unvested restricted or phantom units, except that, if an award recipient’s service is terminated either by our general partner (or an affiliate) without “cause” or by the award recipient for “good reason” (as such terms are defined in the restricted or phantom unit agreement) within one year following the occurrence of a change of control, all unvested restricted or phantom units will become immediately vested in full. If an award recipient’s service with our general partner or its affiliates is terminated by (i) our general partner with “cause” or (ii) by the award recipient’s resignation and engagement in “Competition” (as such term is defined in the restricted unit agreement) prior to full vesting of the restricted units, then our general partner has the right, but not the obligation, to repurchase the restricted units at a price per restricted unit equal to the lesser of (x) the fair market value of such restricted unit as of the date of the repurchase and (y) the price paid by the award recipient for such restricted unit.
Severance and Change in Control Benefits. We do not provide any severance or change of control benefits to our general partner’s executive officers.
Other Benefits. Memorial Resource does not maintain a defined benefit pension plan for its executive officers, because it believes such plans primarily reward longevity rather than performance. Memorial Resource provides a basic benefits package generally to all employees, which includes a 401(k) plan and health, disability and life insurance. Memorial Resource employees who provide services to us under the omnibus agreement will be entitled to the same basic benefits.
Compensation Committee Report
The board of directors of our general partner does not have a compensation committee. The board of directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis set forth above. Based on this review and discussion, the board of directors of our general partner has approved the Compensation Discussion and Analysis for inclusion in this annual report.
The board of directors of Memorial Production Partners GP LLC
John A. Weinzierl
W. Donald Brunson
Jonathan M. Clarkson
Scott A. Gieselman
Kenneth A. Hersh
P. Michael Highum
Tony R. Weber
Employment Agreements
Neither Memorial Resource nor our general partner has entered into any employment agreements with any of our named executive officers, other than change of control agreements.
Deductibility of Compensation
We believe that the compensation paid to our general partner’s named executive officers is generally fully deductible for federal income tax purposes. We are a limited partnership, and we do not meet the definition of a “corporation” subject to deduction limitations under Section 162(m) of the Code. Accordingly, such limitations do not apply to compensation paid to our general partner’s named executive officers.
Relation of Compensation Policies and Practices to Risk Management
Memorial Resource’s compensation policies and practices are designed to provide rewards for short-term and long-term performance, both on an individual basis and at the entity level. In general, optimal financial and operational performance, particularly in a competitive business, requires some degree of risk-taking. Accordingly, the use of compensation as an incentive for performance can foster the potential for management and others to take unnecessary or excessive risks to reach performance thresholds that qualify them for additional compensation.
From a risk management perspective, our policy is to conduct our commercial activities within pre-defined risk parameters that are closely monitored and are structured in a manner intended to control and minimize the potential for unwarranted risk-taking. We also routinely monitor and measure the execution and performance of our projects and acquisitions relative to expectations.
We expect our compensation arrangements to contain a number of design elements that serve to minimize the incentive for taking unwarranted risk to achieve short-term, unsustainable results. Those elements include delaying the rewards and subjecting such rewards to forfeiture for terminations related to violations of our risk management policies and practices or of our Code of Business Conduct and Ethics.
In combination with our risk-management practices, we do not believe that risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us.
Summary Compensation Table
The following table includes the compensation earned by our general partner’s named executive officers and allocated to us by Memorial Resource for the years ended December 31, 2015, 2014 and 2013.
(1)
Mr. Weinzierl also served as President from April 2011 until January 2014.
(2)
Mr. Stillwell was appointed Vice President, Finance in July 2014 and appointed to Vice President and Chief Financial Officer in January 2015. Mr. Stillwell became a named executive officer in 2014.
(3)
Mr. Cooper has served as Senior Vice President and Chief Operating Officer since November 2014.
(4)
Mr. Roane served as Senior Vice President, General Counsel and Secretary from November 2014 until July 2015, Vice President, General Counsel and Corporate Secretary from January 2014 to November 2014, and General Counsel and Corporate Secretary in 2013.
(5)
Reflects the aggregate grant date fair value of restricted unit awards granted under the LTIP calculated by multiplying the number of restricted units granted to each executive by the closing price of our common units on the date of grant. For information about assumptions made in the valuation of these awards, see Note 11 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”
(6)
Amounts include (i) matching contributions under funded, qualified, defined contribution retirement plans, (ii) quarterly distributions paid on LTIP awards, (iii) the dollar value of life insurance premiums paid on behalf of the officer and (iv) the dollar value of short and long term disability insurance premiums paid on behalf the officer.
(7)
Mr. Weinzierl was awarded a grant of 11,327 restricted units on January 9, 2015 in lieu of his cash bonus for 2015. The grant date fair value of such award is determined by multiplying the number of restricted units granted by the closing price of common units on the date of grant of $15.45 per unit.
The following supplemental table presents the components of “All Other Compensation” for each named executive officer for the year ended December 31, 2015:
Grants of Plan-Based Awards
The following table sets forth certain information with respect to grants of plan-based awards to our named executive officers in 2015.
(1)
Represents the amount of restricted common units awarded to our named executive officers under the LTIP, none of which are tied to performance based criteria.
(2)
Reflects the aggregate grant date fair value of restricted unit awards granted under the LTIP calculated by multiplying the number of restricted units granted to each executive by the closing price of our common units on the date of grant. For information about assumptions made in the valuation of these awards, see Note 11 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”
Outstanding Equity Awards
The following table sets forth certain information with respect to outstanding equity awards at December 31, 2015.
(1)
One-third vests on the first, second, and third anniversaries of each date of grant. Of the 469,399 non-vested restricted common unit awards presented in the table, approximately 224,475 vest in 2016, 166,792 vest in 2017 and 78,132 vest in 2018. There were 15,387 restricted common units that vested on January 9, 2016.
(2)
Amounts derived by multiplying the total number of restricted common unit awards outstanding for each named executive officer by the closing price of our common units at December 31, 2015 of $2.64 per unit.
Option Exercises and Stock Vested
The following table sets forth certain information with respect to equity-based awards held by our named executive officers, which vested in 2015.
(1)
One-third vests on the first, second, and third anniversaries of each date of grant. There were 15,387 restricted common units that vested on January 9, 2016.
(2)
Represents gross vesting amounts prior to any units withheld for taxes.
(3)
Amounts derived by multiplying the total number of restricted common unit awards outstanding for each named executive officer by the closing price of our common units on the respective vesting date.
Pension Benefits
Currently, our general partner does not, and does not intend to, provide pension benefits to our general partner’s named executive officers. Memorial Resource may revisit this policy in the future.
Nonqualified Deferred Compensation
Currently, our general partner does not, and does not intend to, sponsor or adopt a nonqualified deferred compensation plan. Memorial Resource may revisit this policy in the future.
Potential Payments Upon Termination or Change in Control
Awards under our LTIP may vest and/or become exercisable, as applicable, upon a “change of control” of us or our general partner, as determined by the plan administrator. Under our LTIP, a “change of control” will be deemed to have occurred upon one or more of the following events (i) the directors of Memorial Resource appointed by the Funds or their affiliates do not constitute a majority of the board of directors of Memorial Resource; (ii) Memorial Resource, the Funds or any of their affiliates do not have the right to appoint or nominate a majority of the board of directors of our general partner; (iii) the members of our general partner approve and implement, in one or a series of transactions, a plan of complete liquidation of our general partner; (iv) the sale or other disposition by our general partner of all or substantially all of its assets in one or more transactions to any person or entity other than our general partner or an affiliate of our general partner or the Funds; or (v) a person or entity other than our general partner or an affiliate of our general partner or the Funds becomes the general partner of us. The consequences of the termination of a grantee’s employment, consulting arrangement or membership on the board of directors will be determined by the plan administrator in the terms of the relevant award agreement.
The following table quantifies our best estimates as to the amounts that each of our named executive officers would be entitled to receive upon a change of control, as applicable, assuming that such event occurred on December 31, 2015 and using our closing common unit price on such date of $2.64. The precise amount that each of our named executive officers would receive cannot be determined with any certainty until a change of control has occurred. Therefore, such amounts should be considered “forward-looking statements.”
Director Compensation
Officers or employees of our general partner or its affiliates, including Memorial Resource, the Funds, and NGP, who also serve as directors of our general partner do not receive additional compensation for their service as a director of our general partner. Each director who is not an officer or employee of our general partner or its affiliates receives compensation as a “non-employee director” for attending meetings of the board of directors, as well as committee meetings. The following table presents information regarding compensation paid to the independent directors of our general partner during the year ended December 31, 2015.
(1)
Serves as chairman of the audit committee.
(2)
Reflects the aggregate grant date fair value of restricted common unit awards granted under the LTIP calculated by multiplying the number of restricted common units granted to each director by the closing price of our common units on the date of grant ($15.45 with respect to the grants made to Messrs. Clarkson, Highum and Brunson on January 9, 2015). For information about assumptions made in the valuation of these awards, see Note 11 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.” At December 31, 2015, Messrs. Clarkson, Highum, and Brunson had 9,434; 9,434; and 8,091 restricted units outstanding, respectively.
(3)
Represents quarterly distribution paid on LTIP Awards.
For 2016, the following compensation has been approved for the non-employee directors:
·
an annual retainer of $125,000 for each director payable quarterly in arrears;
·
an annual equity grant under our LTIP of $125,000 of phantom units based on the price per common unit on the date of grant, which will vest one year from the date of grant; and
·
an annual retainer of $7,500 for the chairman of the audit committee.
The phantom units were awarded to the non-employee directors in January 2016 and vest in January 2017. The awards included DERs pursuant to which the recipient will receive a cash payment with respect to each phantom unit equal to any cash distribution that we pay to a holder of a common unit. Upon vesting, the phantom units shall 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.
In addition, non-employee directors are reimbursed for all out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director is fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.
Compensation Committee Interlocks and Insider Participation
As a limited partnership, we are not required by NASDAQ to establish a compensation committee. Although the board of directors of our general partner does not currently intend to establish a compensation committee, it may do so in the future.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
As of January 31, 2016, the following table sets forth the beneficial ownership of our common units that are owned by:
·
each person known by us to be a beneficial owner of more than 5% of our outstanding common units;
·
each director of our general partner;
·
each named executive officer of our general partner; and
·
all directors and executive officers of our general partner as a group.
(1)
The address for all beneficial owners in this table is 500 Dallas Street, Suite 1800, Houston, Texas 77002.
(2)
Includes common units purchased in the directed unit program at the closing of our initial public offering as well as restricted common units awarded under the Memorial Production Partners GP LLC Long-Term Incentive Plan.
(3)
Based on 82,943,323 common units outstanding.
Our general partner’s independent directors also beneficially own derivative securities. On January 8, 2016, each independent director of our general partner was awarded 51,867 phantom units, which vest on January 8, 2017. The awards included DERs pursuant to which the recipient will receive a cash payment with respect to each phantom unit equal to any cash distribution that we pay to a holder of a common unit. Upon vesting, the phantom units shall 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. See Item 11. “Executive Compensation” for additional information.
Memorial Production Partners GP LLC, our general partner, owns 50% of all of our IDRs and a 0.1% general partner interest in us. The following table sets forth the approximate beneficial ownership of equity interests in our general partner.
(1)
In December 2013, our general partner redeemed all non-voting interests owned by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore” and, together with NGP VIII and NGP IX, the “Funds”). In consideration for this redemption, the Funds received 50% of our incentive distribution rights. Memorial Resource owns 100% of the sole member interests in our general partner, which are classified as Class A membership interests, and will be entitled to 50% of any cash distributions made or common units issued to our general partner with respect to our general partner’s 0.1% general partner interest in us.
(2)
Our general partner is controlled by Memorial Resource. MRD Holdco LLC, a holding company controlled by the Funds (“MRD Holdco”), together with a group controls Memorial Resource. MRD Holdco is controlled by NGP VIII, NGP IX and NGP IX Offshore. Mr. Hersh will share in distributions made by us with respect to interests held by our general partner in proportion to his pecuniary interests. Mr. Hersh disclaims beneficial ownership of the reported securities in excess of his pecuniary interest in such securities. In addition, our general partner’s other non-independent directors and certain of our general partner’s executive officers have indirect financial interests in Memorial Resource and its affiliates.
(3)
NGP VIII, NGP IX and NGP IX Offshore may be deemed to share voting and dispositive power over the reported interests of MRD Holdco; thus, each of NGP VIII, NGP IX and NGP IX Offshore may also be deemed to be the beneficial owner of these interests. Each of NGP VIII, NGP IX and NGP IX Offshore disclaims beneficial ownership of such reported interests in excess of such entity’s respective pecuniary interest in such interests. G.F.W. Energy VIII, L.P., GFW VIII, L.L.C., G.F.W. Energy IX, L.P. and GFW IX, L.L.C. may be deemed to beneficially own the interests owned by MRD Holdco attributable to NGP VIII, NGP IX and NGP IX Offshore and the interests held by NGP VIII, NGP IX and NGP IX Offshore by virtue of GFW VIII, L.L.C. being the sole general partner of G.F.W. Energy VIII, L.P. (which is the general partner of NGP VIII) and GFW IX, L.L.C. being the sole general partner of G.F.W. Energy IX, L.P. (which is the general partner of NGP IX and NGP IX Offshore). Kenneth A. Hersh, one of our general partner’s directors and an Authorized Member of each of GFW VIII, L.L.C. and GFW IX, L.L.C., may also be deemed to share the power to vote, or to direct the vote, and to dispose, or to direct the disposition, of the interests held by NGP VIII, NGP IX and NGP IX Offshore. Mr. Hersh does not own directly any interests in our general partner.
(4)
The address for NGP VIII, NGP IX and NGP IX Offshore is 5221 N. O’Connor Boulevard, Suite 1100, Irving, Texas 75039.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table summarizes information about our equity compensation plans as of December 31, 2015:
(1)
Our general partner adopted the Memorial Production Partners GP LLC Long-Term Incentive Plan in December 2011 in connection with the completion of our initial public offering. See “Item 11. Executive Compensation-Compensation Discussion and Analysis-Elements of Executive Compensation-Long Term Incentive Compensation” for additional information.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Memorial Resource owns 100% of the voting membership interests in our general partner, and the Funds collectively indirectly own 50% of our incentive distribution rights. As of January 31, 2016, our general partner owns an approximate 0.1% general partner interest in us, evidenced by 86,797 general partner units, and 50% of our incentive distribution rights.
Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments made by us to our general partner and its affiliates in connection with our formation and, pursuant to arrangements entered into in connection with our initial public offering, to be made in connection with our ongoing operation and any liquidation. These distributions and payments were determined by and among affiliated entities before our initial public offering and, consequently, were not the result of arm’s-length negotiations.
Formation Stage
The consideration received by our general partner and Memorial Resource prior to or in connection with our initial public offering
·
7,061,294 common units. All of these units were sold to the public in a secondary offering by Memorial Resource in November 2013;
·
5,360,912 subordinated units, all of which converted to common units on February 13, 2015. MRD Holdco sold all of such common units and no longer owns any of our common units;
·
21,444 general partner units;
·
all of our incentive distribution rights (50% of which were transferred to the Funds in December 2013); and
·
approximately $280 million in cash.
Operational Stage
Distributions of available cash to our general partner and its affiliates
We will generally make cash distributions 99.9% to our unitholders, pro rata and 0.1% to our general partner, assuming it makes any capital contributions necessary to maintain its 0.1% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to a maximum of 25.0% of the distributions above the highest target distribution level, including the general partner’s 0.1% general partner interest.
Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual distribution of less than $0.1 million on its general partner units.
For the twelve months ended December 31, 2015, our general partner and its affiliates received an aggregate of $3.3 million in cash distributions from us, which consisted of approximately $3.0 million in respect of subordinated units prior to their conversion to common units and approximately $0.3 million in respect of our general partner units and the general partner’s incentive distribution rights.
Payments to our general partner and its affiliates
Our general partner will not receive a management fee or other compensation for its management of our partnership, but we will reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner and its affiliates in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine in good faith the amount of such expenses that are allocable to us.
For the twelve months ended December 31, 2015, we reimbursed our general partner and its affiliates an aggregate of $27.0 million for all direct and indirect expenses incurred or payments made on our behalf and all other expenses allocable to us or otherwise incurred in connection with operating our business
Withdrawal or removal of our general partner
If our general partner is removed under circumstances where cause exists or withdraws and such withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the departing general partner’s general partner interest in us and the incentive distribution rights for a cash payment equal to the fair market value of those interests. Under all other circumstances in which our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the departing general partner’s general partner interest in us and its incentive distribution rights for their fair market value or to convert such interests into common units.
Liquidation Stage
Liquidation
Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.
Third Amended and Restated Limited Liability Company Agreement of Memorial Production Partners GP LLC
Memorial Production Partners GP LLC, our general partner and a wholly-owned subsidiary of Memorial Resource, owns a 0.1% general partner interest in us and 50% of our IDRs. Under our general partner’s third amended and restated limited liability company agreement, the sole member interests in our general partner are classified as Class A membership interests. Memorial Resource owns all of the Class A membership interests in our general partner. The Class A membership interests are the sole voting interests in our general partner and entitle Memorial Resource, as the Class A member, to all distributions we make to our general partner (including distributions with respect to our general partner’s 0.1% general partner interest in us).
Memorial Resource may transfer, pledge or assign all or any portion of its membership interest in our general partner at any time.
Related Party Agreements
We and certain of our affiliates have entered into various documents and agreements. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations.
Omnibus Agreement
In December 2011, in connection with the closing of our initial public offering, we entered into an omnibus agreement with our general partner and MRD LLC. Memorial Resource succeeded to all of MRD LLC’s duties and obligations under the omnibus agreement in connection with certain restructuring transactions at the time of Memorial Resource’s initial public offering.
Pursuant to the omnibus agreement, we are required to reimburse Memorial Resource for all expenses incurred by Memorial Resource (or payments made on our behalf) in conjunction with its provision of general and administrative services to us, including, but not limited to, our public company expenses and an allocated portion of the salary and benefits of the executive officers of our general partner and other employees of Memorial Resource who perform services for us or on our behalf. We are also obligated to reimburse Memorial Resource for insurance coverage expenses it incurs with respect to our business and operations and with respect to director and officer liability coverage for the officers and directors of our general partner.
Pursuant to the omnibus agreement, Memorial Resource will indemnify our general partner and us against income taxes attributable to pre-closing ownership or operation of the assets we acquired in connection with our initial public offering, including any income tax liabilities related to such acquisition occurring on or prior to the closing of our initial public offering.
Memorial Resource’s indemnification obligation will survive for sixty days after the expiration of the applicable statute of limitations with respect to income taxes.
Pursuant to the omnibus agreement, we must indemnify Memorial Resource for any liabilities incurred by Memorial Resource attributable to the operating and administrative services provided to us under the omnibus agreement, other than liabilities resulting from Memorial Resource’s bad faith, fraud, gross negligence or willful misconduct. In addition, Memorial Resource must indemnify us for any liability we incur as a result of Memorial Resource’s bad faith or willful misconduct in providing operating and administrative services under the omnibus agreement. Memorial Resource may terminate the omnibus agreement in the event that it ceases to be an affiliate of us and may also terminate the omnibus agreement in the event of our material breach of the agreement, including failure to pay amounts due thereunder in accordance with its terms.
Under the omnibus agreement, none of the parties thereto nor any of their respective affiliates have any obligation to offer, or provide any opportunity to pursue, purchase or invest in, any business opportunity to any other party or their affiliates. Furthermore, the omnibus agreement does not restrict any of the parties thereto and their respective affiliates from competing with either Memorial Resource or our general partner and us.
Classic Agreements
In November 2011, Classic Hydrocarbons Operating, LLC, a subsidiary of Memorial Resource (“Classic Operating”), and Classic Pipeline & Gathering, LLC (“Classic Pipeline”), a subsidiary of MRD Holdco, entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. In May 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement had a term until December 31, 2023, subject to one-year extensions at either party’s election. The amended gas gathering agreement was terminated in November 2015 in connection with a third party’s acquisition of Classic Pipeline’s Joaquin gathering system.
In May 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement has a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline. Effective July 1, 2015, the fee was reduced to $0.40 per barrel. In February 2015, in connection with and as part of the Property Swap, Classic Hydrocarbons Holdings, L.P. sold all of the equity interests owned by it in Classic Operating as well as Craton Energy GP III, LLC (“Craton GP”) and Craton Energy Holdings III, LP (“Craton LP”), two subsidiaries of Memorial Resource, to OLLC, and Classic Operating, Craton GP and Craton LP were merged into OLLC. OLLC is therefore the successor to Classic Operating under the terminated amended gas gathering agreement and water disposal agreement. In November 2015, MRD Holdco contributed its salt water disposal system to us.
Acquisitions of Oil and Natural Gas Producing Properties
Property Swap
In February 2015, we and Memorial Resource completed a transaction in which we exchanged our oil and gas properties in North Louisiana and approximately $78.4 million in cash for Memorial Resource’s East Texas and Louisiana oil and gas properties. The transaction had an effective date of January 1, 2015. The properties MEMP received are primarily located in the Joaquin Field in Shelby and Panola counties in East Texas.
The above transaction was approved by the general partner’s board of directors and by its conflicts committee. Some of the executive officers of our general partner hold similar positions with Memorial Resource, and many of the directors of our general partner own economic interests, investments and other economic incentives in affiliates of Memorial Resource. All of our general partner’s non-independent directors also have indirect economic interests in the Funds that entitle them to a portion of the profits generated by the Funds in excess of certain return thresholds.
Review, Approval or Ratification of Transactions with Related Persons
The board of directors of our general partner has adopted a Code of Business Conduct and Ethics that sets forth our policies for the review, approval and ratification of transactions with related persons. Pursuant to the Code of Business Conduct and Ethics, a director is expected to bring to the attention of the Chief Executive Officer or the board of directors of our general partner any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict will be addressed in accordance with Memorial Resource’s and our general partner’s organizational documents and the provisions of our partnership agreement. The resolution may be determined by disinterested directors, our general partner’s board of directors, or the conflicts committee of our general partner’s board of directors. Our Code of Business Conduct and Ethics is available within the “Corporate Governance” section of our website at http://investor.memorialpp.com/governance.cfm.
Under the Code of Business Conduct and Ethics, any executive officer of our general partner is required to avoid conflicts of interest unless approved by the board of directors. The board of directors of our general partner establishes a conflicts committee from time to time comprised of three independent directors. Our general partner may, but is not required to, seek the approval of the conflicts committee in connection with future acquisitions from (or other transactions with) Memorial Resource or any of its affiliates. In the case of any sale of equity or debt by us to Memorial Resource or any of its affiliates, we anticipate that our practice will be to obtain the approval of the conflicts committee for the transaction. The conflicts committee is entitled to hire its own financial and legal advisors in connection with any matters on which the board of directors of our general partner has sought the conflicts committee’s approval.
Memorial Resource and its affiliates are free to offer properties to us on terms it or they deem acceptable, and the board of directors of our general partner (or the conflicts committee) is free to accept or reject any such offers, negotiating terms it deems acceptable to us. As a result, the board of directors of our general partner (or the conflicts committee) will decide, in its sole discretion, the appropriate value of any assets offered to us by Memorial Resource or its affiliates. In so doing, we expect the board of directors (or the conflicts committee) will consider a number of factors in its determination of value, including, without limitation, production and reserve data, operating cost structure, current and projected cash flows, financing costs, the anticipated impact on distributions to our unitholders, production decline profile, commodity price outlook, reserve life, future drilling inventory and the weighting of the expected production between oil and natural gas.
We expect that Memorial Resource and its affiliates will consider a number of the same factors considered by the board of directors of our general partner to determine the proposed price for any assets it or they may offer to us in future periods. In addition to these factors, given that Memorial Resource controls our general partner and considering its and the Funds’ interest in our incentive distribution rights, it and they may consider the potential positive impact on their underlying investment in us by offering properties to us at attractive purchase prices. Likewise, it and they may consider the potential negative impact on their underlying investment in us if we are unable to acquire additional assets on favorable terms, including the negotiated purchase price.
Director Independence
NASDAQ does not require a listed publicly traded partnership like us to have a majority of independent directors on the board of directors of our general partner. For a discussion of the independence of the board of directors of our general partner, please see “Item 10 - Directors, Executive Officers and Corporate Governance-Management.”
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
The audit committee of the board of directors of our general partner selected KPMG LLP (“KPMG”), an independent registered public accounting firm, to audit our consolidated and combined financial statements for the year ended December 31, 2015. The audit committee’s charter requires the audit committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. All services reported in the audit, audit-related, tax and all other fees categories below with respect to this annual report for the year ended December 31, 2015 were approved by the audit committee.
The following table summarizes the aggregate KPMG fees for independent auditing, tax and related services for each of the last two fiscal years (dollars in thousands):
(1)
Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. For 2015 and 2014, those fees primarily related to the (i) audit of our annual financial statements and internal controls over financial reporting included in our annual reports, (ii) the review of our quarterly financial statements filed on Form 10-Q, and (iii) services in connection with the Partnership’s acquisitions.
(2)
Audit-related fees represent amounts billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews. No such services were rendered by KPMG during the years ended December 31, 2015 and 2014.
(3)
Tax fees represent amounts billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice, and tax planning. No such services were rendered by KPMG during the year ended December 31, 2015.
(4)
All other fees represent amounts billed in each of the years presented for services not classifiable under the other categories listed in the table above. No such services were rendered by KPMG during the years ended December 31, 2015 and 2014.
Audit Committee Approval of Audit and Non-Audit Services
The audit committee of the board of directors of our general partner has adopted a pre-approval policy with respect to services which may be performed by KPMG. This policy lists specific audit-related services as well as any other services that KPMG is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional audit committee authorization. The audit committee receives quarterly reports on the status of expenditures pursuant to the pre-approval policy. The audit committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the audit committee prior to engagement.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) Financial Statements
Our Consolidated and Combined Financial Statements are included under Part II, Item 8 of the Annual Report. For a listing of these statements and accompanying footnotes, see “Index to Financial Statements” Page of this Annual Report.
(a)(2) Financial Statement Schedules
All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated and combined financial statements or notes thereto.
(a)(3) Exhibits
The exhibits listed on the accompanying Exhibit Index are filed or incorporated by reference as part of this report, and such Exhibit Index is incorporated herein by reference.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
Memorial Production Partners LP
(Registrant)
By:
Memorial Production Partners GP LLC, its general partner
Date: February 24, 2016
By:
/s/ Robert L. Stillwell, Jr.
Robert L. Stillwell, Jr.
Vice President and Chief Financial Officer of
Memorial Production Partners GP LLC
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MEMORIAL PRODUCTION PARTNERS LP
Page No.
Report of Independent Registered Public Accounting Firm
Consolidated and Combined Balance Sheets as of December 31, 2015 and 2014
Statements of Consolidated and Combined Operations for the Years Ended December 31, 2015, 2014, and 2013
Statements of Consolidated and Combined Cash Flows for the Years Ended December 31, 2015, 2014, and 2013
Statements of Consolidated and Combined Equity for the Years Ended December 31, 2015, 2014, and 2013
Notes to Consolidated and Combined Financial Statements
Note 1 - Organization and Basis of Presentation
Note 2 - Summary of Significant Accounting Policies
Note 3 - Acquisitions and Divestitures
Note 4 - Fair Value Measurements of Financial Instruments
Note 5 - Risk Management and Derivative Instruments
Note 6 - Asset Retirement Obligations
Note 7 - Restricted Investments
Note 8 - Long Term Debt
Note 9 - Equity and Distributions
Note 10 - Earnings per Unit
Note 11 - Equity-based Awards
Note 12 - Related Party Transactions
Note 13 - Commitments and Contingencies
Note 14 - Income Tax
Note 15 - Quarterly Financial Information (Unaudited)
Note 16 - Supplemental Oil and Gas Information (Unaudited)
F- 1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Memorial Production Partners GP LLC and
Unitholders of Memorial Production Partners LP
We have audited the accompanying consolidated balance sheet of Memorial Production Partners LP and subsidiaries (the Partnership) as of December 31, 2015, the consolidated and combined balance sheet of Memorial Production Partners LP as of December 31, 2014, and the related consolidated and combined statements of operations, equity, and cash flows for each of the years in the three-year period ended December 31, 2015. These consolidated and combined financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated and combined financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated and combined financial statements referred to above present fairly, in all material respects, the financial position of Memorial Production Partners LP and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 1 to the consolidated and combined financial statements, the balance sheet as of December 31, 2014, and the related statements of operations, equity, and cash flows for each of the years in the three-year period ended December 31, 2015 have been prepared on a combined basis of accounting.
As discussed in Note 1 and Note 2 to the consolidated and combined financial statements, Memorial Production Partners LP changed its method of accounting for debt issuance costs effective January 1, 2014 due to the adoption of FASB ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. Additionally, as discussed in Note 1 and Note 2 to the consolidated and combined financial statements, Memorial Production Partners LP changed its method of accounting for deferred income taxes effective January 1, 2014 due to the adoption of FASB ASU 2015-17, Balance Sheet Classification of Deferred Taxes.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Memorial Production Partners LP and subsidiaries’ internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 24, 2016 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 24, 2016
F- 2
MEMORIAL PRODUCTION PARTNERS LP
CONSOLIDATED AND COMBINED BALANCE SHEETS
(In thousands, except outstanding units)
See Accompanying Notes to Consolidated and Combined Financial Statements.
* See Note 1 for information regarding recast amounts and basis of financial statement presentation
F- 3
MEMORIAL PRODUCTION PARTNERS LP
STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS
(In thousands, except per unit amounts)
See Accompanying Notes to Consolidated and Combined Financial Statements.
*See Note 1 for information regarding recast amounts and basis of financial statement presentation.
F- 4
MEMORIAL PRODUCTION PARTNERS LP
STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS
(In thousands)
See Accompanying Notes to Consolidated and Combined Financial Statements.
*See Note 1 for information regarding recast amounts and basis of financial statement presentation.
See Note 2 for Supplemental Cash Flow information
F- 5
MEMORIAL PRODUCTION PARTNERS LP
STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY
(In thousands)
See Accompanying Notes to Consolidated and Combined Financial Statements.
*See Note 1 for information regarding recast amounts and basis of financial statement presentation.
F- 6
MEMORIAL PRODUCTION PARTNERS LP
NOTES TO 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 there are not different economic environments 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, Colorado, 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; (ii) “Memorial Resource” refer collectively to Memorial Resource Development Corp. and its subsidiaries other than the Partnership; (iii) “MRD LLC” refer to Memorial Resource Development LLC, which is the predecessor of Memorial Resource; (iv) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P.; (v) “OLLC” refer to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties; (vi) “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; (vii) “MRD Holdco” refer to MRD Holdco LLC, which together with a group, controls Memorial Resource; and (viii) “NGP” refer to Natural Gas Partners.
The Partnership is owned 99.9% by its limited partners and 0.1% by MEMP GP, which is a wholly-owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership’s operations and activities. Memorial Resource provides management, administrative and operations personnel to us and our general partner under an omnibus agreement (see Note 12). The Funds, which are three of the private equity funds managed by NGP, collectively control MRD Holdco. The Funds collectively indirectly own 50% of our incentive distribution rights (“IDRs”). The remaining IDRs are owned by our general partner.
Previous Owners
References to “the previous owners” for accounting and financial reporting purposes refer collectively to:
·
Certain oil and natural gas properties and related assets in East Texas and North Louisiana that the Partnership acquired in March 2013 from WHT Energy Partners (“WHT”) (the “WHT Properties”).
·
Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that the Partnership acquired through equity and asset transactions on October 1, 2013 from both MRD LLC and certain affiliates of NGP as discussed below. We refer to this transaction as the “Cinco Group acquisition.”
·
Certain oil and natural gas properties primarily located in East Texas and assets in Louisiana that the Partnership acquired in February 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. 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 (“Classic”).
Each of these aforementioned acquisitions 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 has been retrospectively revised to give effect to such acquisitions as if the Partnership owned the assets for periods after common control commenced through their respective acquisition dates. See Note 12 for additional information.
F- 7
MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
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 were derived from the historical accounting records of the previous owners and reflect the historical financial position, results of operations and cash flows for all periods presented.
The previous owners combined financial statements reflect: (i) the WHT Properties, (ii) the financial statements of Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits overriding royalty interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), Stanolind Oil and Gas SPV LLC (“Stanolind SPV”), Tanos Energy, LLC (“Tanos”), together with its wholly-owned subsidiaries, Prospect Energy, LLC (“Prospect”), and certain oil and natural gas properties in Jackson County, Texas (the “MRD Assets”) (collectively, the “Cinco Group”) on a combined basis for periods after common control commenced through the date of acquisition. The Partnership acquired substantially all of the Cinco Group on October 1, 2013 from: (a) Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds, and (b) MRD LLC.
The ownership interest of the noncontrolling shareholder in the San Pedro Bay Pipeline Company (“SPBPC”), an indirect majority-owned subsidiary of REO, was presented as noncontrolling interest in the financial statements for the periods prior to November 3, 2015. On November 3, 2015, we purchased the noncontrolling interest in SPBPC for approximately $6.0 million and completed an acquisition of the remaining interests in our oil and gas properties offshore Southern California (the “Beta properties”) from a third party for approximately $94.6 million (the “2015 Beta Acquisition”). See Note 3 for additional information regarding the 2015 Beta Acquisition.
All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item.
We have elected to early adopt new accounting pronouncements related to the presentation of deferred taxes and debt issuance costs as of December 31, 2015. See Note 2 for more information. A retrospective change to the December 31, 2014 balance sheet as previously presented was required due to the adoption. The retrospective adjustment to the December 31, 2014 balance sheet is shown below:
Note 2. Summary of Significant Accounting Policies
Use of Estimates
The preparation of consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
F- 8
MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
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.
Principles of Consolidation and Combination
Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. Likewise, the combined financial statements include the accounts of the previous owners as discussed above. All material intercompany balances and transactions have been eliminated.
Cash and Cash Equivalents
Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less.
Concentrations of Credit Risk
Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These restricted investments consist of money market deposit accounts, money market mutual funds, and commercial paper, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. Neither we nor and the previous owners have experienced any losses from such instruments.
Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us and the previous owners. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2015 and 2014, respectively.
If we were to lose any one of our customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified.
Oil and Natural Gas Properties
Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves
F- 9
MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred.
As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. Support equipment and facilities, which are primarily related to our Wyoming and California assets, are depreciated using the straight-line method generally based on estimated useful lives of fifteen to forty years.
On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized.
There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2015, 2014 and 2013.
Oil and Gas Reserves
The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. We engaged Ryder Scott Company, L.P. (“Ryder Scott”), our independent reserve engineers, to audit our internally prepared reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2015.
Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.
Other Property & Equipment
Other property and equipment is stated at historical cost and is comprised primarily of vehicles, furniture, fixtures, and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to five years.
Restricted Investments
Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense, net in the statement of operations. These restricted investments may consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information.
Debt Issuance Costs
These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method and generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2015, 2014 and 2013 was approximately $6.1 million, $4.2 million, and $6.0 million, respectively.
F- 10
MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Impairments
Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Impairment expense for the years ended December 31, 2015, 2014 and 2013 was approximately $616.8 million, $407.5 million, and $4.1 million, respectively.
Asset Retirement Obligations
An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized in net income (loss) to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations.
Book Overdrafts
Book overdrafts, representing outstanding checks in excess of funds on deposit, are classified as accounts payable and the change in the related balance is reflected in operating activities in the statement of cash flows.
Revenue Recognition
Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2015 or 2014.
The following individual customers each accounted for 10% or more of total reported revenues for the period indicated:
General and Administrative Expense
We and our general partner have entered into an omnibus agreement with a wholly-owned subsidiary of Memorial Resource pursuant to which, among other things, Memorial Resource performs all operational, management and administrative services on our general partner’s and our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocated to us, including expenses incurred by our general partner and its affiliates on our behalf. Memorial Resource allocated indirect general and administrative costs based on time allocations for the years ended December 31, 2015 and 2014 and on production for the year ended December 31, 2013. Under our partnership agreement and the omnibus agreement, we reimburse Memorial Resource for all direct and indirect costs incurred on our behalf. See Note 12 for additional information regarding the omnibus agreement.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
General and administrative expenses associated with the previous owners included the costs of administrative employees, related benefits, office rents, professional fees and other costs not directly associated with field operations or production.
Derivative Instruments
Commodity derivative financial instruments (e.g., swaps, floors, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions.
Capitalized Interest
We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. For the years ended December 31, 2015 and 2014, we had $2.1 million and $2.8 million in capitalized interest, respectively. We did not have any capitalized interest for the year ended December 31, 2013.
Income Tax
We are organized as a pass-through entity for federal and most state income tax purposes. As a result, our partners are responsible for federal and state income taxes on their share of our taxable income. Certain of our consolidated subsidiaries are taxed as corporations for federal and state income tax purposes. We are also subject to the Texas margin tax for partnership activity in the state of Texas.
We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. We recognize interest and penalties accrued to unrecognized tax benefits in other income (expense) in our consolidated statement of operations.
We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority.
Earnings Per Unit
Basic and diluted earnings per unit (“EPU”) is determined by dividing net income or loss available to the limited partners by the weighted average number of outstanding limited partner units during the period. Net income or loss available to the limited partners is determined by applying the two-class method. The two-class method of computing EPU is an earnings allocation formula that determines EPU based on distributions declared. The amount of net income or loss used in the determination of EPU is reduced (or increased) by the amount of available cash that has been or will be distributed to the limited partners for that corresponding period. The remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the limited partners in accordance with the contractual terms of the partnership agreement. The total earnings allocated to the limited partners is determined by adding together the amount allocated for distributions declared and the amount allocated for the undistributed earnings or excess distributions over earnings. Basic and diluted EPU are equivalent, as all restricted common units and subordinated units participate in distributions. See Note 10 for additional information.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Equity Compensation
The fair value of equity-classified awards (e.g., restricted common unit awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards (e.g., phantom units awards) are recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period. We currently have no awards subject to performance criteria; however, such awards would vest when it is probable that the performance criteria will be met and the requisite service period has been met. Generally, no compensation expense is recognized for equity instruments that do not vest. See Note 11 for further information.
Incentive Units
The governing documents of certain entities within the Cinco Group provided for the issuance of incentive units. The incentive units were accounted for as liability awards with compensation expense based on period-end fair value. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. Tanos recognized compensation expense related to the forfeiture of incentive units during April 2013 as further discussed in Note 12.
Accrued Liabilities
Current accrued liabilities consisted of the following at the dates indicated (in thousands):
Supplemental Cash Flows
Supplemental cash flow for the periods presented (in thousands):
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
New Accounting Pronouncements
Balance Sheet Classification of Deferred Taxes. In November 2015, the FASB issued an accounting standards update that requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendments. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The amendments may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We adopted this guidance and applied the disclosure requirements retrospectively to the consolidated financial statements and footnote disclosure.
Simplifying the Accounting for Measurement-Period Adjustments. In September 2015, the Board FASB issued an accounting standards update that eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, an acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. Disclosure of the effect on earnings of any amounts an acquirer would have recorded in previous periods if the accounting had been completed at the acquisition date is required. The disclosure is required for each affected income statement line item and may be presented separately on the face of the income statement or in the notes to the financial statements. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date and is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been issued. The Partnership does not expect the impact of adopting this guidance to be material to the Partnership’s financial statements and related disclosures.
Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. In August 2015, the FASB issued an accounting standards update that formally delayed the effective date of its new revenue recognition standard. The new standard is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Early adoption is now permitted for fiscal years, and interim periods within those years, beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Partnership beginning on January 1, 2018. The Partnership has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures.
Presentation of Debt Issuance Cost. In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Partnership has chosen to adopt this standard and have applied this guidance in its consolidated financial statements and footnote disclosures.
In August 2015, the FASB issued an accounting standards update that incorporates SEC guidance clarifying that debt issuance costs related to line-of-credit arrangements can be deferred and presented as an asset that is subsequently amortized over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Partnership has elected this presentation in its consolidated financial statements and footnote disclosure.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
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 also are required. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted. 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 Partnership does not expect the impact of adopting this guidance will be material to the Partnership’s 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
The third party acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, we and the previous owners conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while acquisition costs associated with the acquisitions were expensed as incurred. The operating revenues and expenses of acquired properties are included in the accompanying financial statements from their respective closing dates forward. The transactions were financed through capital contributions and borrowings under credit facilities.
The fair values of oil and natural gas properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural properties include estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital.
The Partnership has consummated several common control acquisitions since completing its IPO in December 2011, as further discussed in Note 12, directly or indirectly from Memorial Resource and certain affiliates of NGP.
Acquisition-related costs
Acquisition-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):
2015 Acquisitions
2015 Beta Acquisition. As previously disclosed in Note 1, we closed the 2015 Beta Acquisition on November 3, 2015. During the year ended December 31, 2015, we recorded revenues of $3.6 million in the statement of operations and generated losses of approximately $1.0 million related to the 2015 Beta Acquisition subsequent to the closing date. The following table summarizes the fair value of the third party assets acquired and liabilities assumed in the 2015 Beta Acquisition (in thousands):
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2015 and 2014 as though the 2015 Beta Acquisition had been completed on January 1, 2014. The unaudited pro forma financial information was derived from the historical 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.
2014 Acquisitions
Wyoming Acquisition. On July 1, 2014, we consummated a transaction to acquire certain oil and natural gas liquids properties in Wyoming from a third party for a final aggregate purchase price of approximately $906.1 million, after customary post-closing adjustments (the “Wyoming Acquisition”). During the year ended December 31, 2014, we recorded revenues of $72.8 million in the statement of operations and generated earnings of approximately $22.9 million related to the Wyoming Acquisition subsequent to the closing date. The following table summarizes the fair value of the third party assets acquired and liabilities assumed in the Wyoming Acquisition (in thousands):
Eagle Ford Acquisition. On March 25, 2014, we closed a transaction to acquire certain oil and natural gas producing properties in the Eagle Ford from a third party for approximately $168.1 million (the “Eagle Ford Acquisition”). In addition, we acquired a 30% interest in the seller’s Eagle Ford leasehold. During the year ended December 31, 2014, revenues of approximately $36.6 million were recorded in the statement of operations related to the Eagle Ford Acquisition subsequent to the closing date and we generated earnings of approximately $16.3 million for the year ended December 31, 2014.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands):
The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2014 and 2013 as though the Eagle Ford Acquisition and Wyoming Acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the 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 and (iii) interest expense on additional borrowings necessary to finance the acquisitions. 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.
2013 Acquisitions
Third Party. We closed two separate transactions during the year ended December 31, 2013 to acquire certain oil and natural gas properties from third parties in East Texas (the “East Texas Acquisition”) and the Rockies (the “Rockies Acquisition”) for approximately $29.4 million in aggregate. The East Texas Acquisition closed on September 6, 2013 and the Rockies Acquisition closed on August 30, 2013. The following table summarizes the fair value of the third party assets acquired and liabilities assumed as of each acquisition date (in thousands):
The Cinco Group also acquired certain oil and gas properties and leases in Texas from third parties for a final purchase price of $9.3 million.
2015 Divestitures
During the year ended December 31, 2015, we conducted an auction process administered by a third-party and sold interests in certain oil and gas properties located in the Permian Basin in various Texas and New Mexico counties to two third parties of approximately $0.6 million in the aggregate. In addition as part of that auction process, we also sold interests in certain oil and gas properties located in the Permian Basin to a related party for approximately $0.9 million. See Note 12 for additional information regarding this related party divestiture.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Previous Owners’ Divestitures
On January 1, 2013, Tanos sold a natural gas gathering pipeline located in East Texas, which it had originally acquired in April 2010, to a privately held gas transportation company for a minimum of $1.5 million. The maximum allowable additional proceeds are $2.0 million. The contingent consideration is based on the natural gas pipeline servicing any new wells that Tanos drills in the area over the following three years. The contingent consideration portion of an arrangement is recorded when the consideration is determined to be realizable. Tanos recorded an aggregate gain of approximately $1.4 million related to this transaction, of which $0.4 million was contingent consideration. Tanos also sold certain non-operated oil and gas properties in 2013 for $2.9 million and recorded a gain of $1.4 million.
The previous owners sold certain interests in oil and gas properties located offshore Louisiana on October 11, 2012 to an NGP controlled entity and the remaining proceeds of approximately $2.0 million were released from escrow in April 2013.
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). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:
Level 1 - Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is one in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. At December 31, 2015 and 2014, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.
Level 3 - Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity).
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The carrying values of cash and cash equivalents, accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at December 31, 2015 and December 31, 2014. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 8 for the estimated fair value of our outstanding fixed-rate debt.
The fair market values of the derivative financial instruments reflected on the balance sheets as of December 31, 2015 and December 31, 2014 were based on estimated forward commodity prices (including nonperformance risk) and forward interest rate yield curves. Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2015 and December 31, 2014 for each of the fair value hierarchy levels:
See Note 5 for additional information regarding our derivative instruments.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values:
·
The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 6 for a summary of changes in AROs.
·
If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. The fair value of supporting equipment, such as plant assets, acquired in transactions accounted for as business combinations is commonly estimated using the depreciated replacement cost approach.
·
Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.
·
During the year ended December 31, 2015, we recognized $616.8 million of impairments. These impairments primarily related to certain properties located in East Texas, South Texas, the Permian Basin, Wyoming and Colorado. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily as a result of declining commodity prices. As a result of the impairments, the carrying value of these properties was reduced to approximately $408.6 million.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
·
During the year ended December 31, 2014, we recognized $407.5 million of impairments. The impairments primarily related to certain properties located in the Permian Basin, East Texas and South Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable. In the Permian Basin, the impairments were in due to a downward revision of estimated proved reserves based on declining commodity prices and updated well performance data. In South Texas, the impairments were due to a downward revision of estimated proved reserves based on declining commodity prices and increased operating costs. In East Texas, the impairments were due to downward revisions based on declining commodity prices. The carrying value of the: (i) Permian Basin properties after the $234.2 million impairment was approximately $88.7 million; (ii) East Texas properties after the $107.6 million impairment was approximately $88.8 million; and (iii) South Texas properties after the $65.6 million impairment was $71.2 million.
·
During the year ended December 31, 2013, we recognized $4.1 million of impairments. The impairments related to certain properties located in South Texas. The estimated future cash flows expected from South Texas properties were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on pricing terms specific to these properties. The carrying value of these properties after the $4.1 million impairment was approximately $7.3 million.
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 transactions limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease.
Certain inherent business risks are associated with commodity and interest derivative contracts, 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 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. As a result, had certain counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $350.0 million against amounts outstanding under our revolving credit facility at December 31, 2015, reducing our maximum credit exposure to approximately $380.9 million, of which approximately $123.4 million was with a single counterparty. See Note 8 for additional information regarding our revolving credit facility.
Commodity Derivatives
A combination of commodity derivatives (e.g., floating-for-fixed swaps, costless collars, call spreads and basis swaps) is used to manage exposure to commodity price volatility. Historically, the Partnership has not paid or received premiums for put options. In February 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. In February 2015, cash settlement receipts of approximately $27.1 million from the termination of the crude oil derivatives were applied as premiums for the new NGL derivatives. In November 2015, we had cash settlement receipts of $16.4 million from the termination of certain WTI crude oil derivatives that were applied as premiums for new Brent crude oil derivatives. As a part of the 2015 Beta Acquisition, we acquired $4.6 million of commodity derivatives. These derivatives were subsequently restructured by terminating “in-the-money” crude oil derivatives settling in 2015 through 2016 and entering into new crude oil derivatives. Cash settlement receipts of approximately $4.4 million from the termination of the crude oil derivatives were applied as premiums for the new crude oil swaps.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
We enter into natural gas derivative contracts that are indexed to NYMEX Henry Hub and regional indices such as NGPL TXOK, TETCO STX, and Houston Ship Channel in proximity to the Partnership’s areas of production. We also enter into oil derivative contracts indexed to a variety of locations such as NYMEX WTI, Inter-Continental Exchange (“ICE”) Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu. At December 31, 2015, the Partnership had the following open commodity positions:
Our basis swaps included in the table above are presented on a disaggregated basis below:
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Interest Rate Swaps
Periodically, interest rate swaps are entered into to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. At December 31, 2015, we had the following interest rate swap open positions:
Balance Sheet Presentation
The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2015 and 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement.
(Gains) Losses on Derivatives
We do not designate derivative instruments as hedging instruments for accounting and financial reporting purposes and neither did the previous owners. 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 years ending December 31, 2015, 2014, and 2013:
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Note 6. Asset Retirement Obligations
The Partnership’s asset retirement obligations primarily relate to the Partnership’s portion of future plugging and abandonment of wells and related facilities. The following table presents the changes in the asset retirement obligations for the years ended December 31, 2015, 2014, and 2013:
The increase in revisions of estimates during 2015 is related to increases in estimated future plugging and abandonment costs compared to estimates made in prior periods as well as shortening the economic lives of certain of our properties.
Note 7. Restricted Investments
Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. The components of the restricted investment balance are as follows:
The restricted investments balance at December 31, 2015 represents 100% ownership of these properties compared to a 51.75% ownership at December 31, 2014. See Note 3 for additional information regarding the 2015 Beta Acquisition.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Note 8. Long Term Debt
Our consolidated debt obligations consisted of the following at the dates indicated:
(1)
The estimated fair value of our 2021 Senior Notes was $210.0 million and $563.5 million at December 31, 2015 and 2014, respectively.
(2)
The estimated fair value of our 2022 Senior Notes was $149.1 million and $380.0 million at December 31, 2015 and 2014, respectively.
(3)
The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
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.
Borrowing Base
Credit facilities tied to a borrowing base are common throughout the oil and gas industry. The borrowing base for our revolving credit facility was the following at the date indicated:
OLLC Revolving Credit Facility
OLLC is a party to a $2.0 billion revolving credit facility, which is guaranteed by us and certain of our current and future subsidiaries.
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, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Borrowings under the revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 80% of the total value of our oil and natural gas properties, and all of our equity interests in OLLC and any future guarantor subsidiaries and all of our other assets including personal property. Additionally, borrowings under our revolving credit facility bear interest, at our option, at either: (i) the Alternate Base Rate defined as the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage, or (iii) the applicable LIBOR Market Index Rate plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.
Our revolving credit facility requires us to maintain a ratio of Consolidated EBITDAX to Consolidated Net Interest Expense (as each term is defined under our revolving credit facility), which we refer to as the interest coverage ratio, of not less than 2.5 to 1.0, and a ratio of consolidated current assets to consolidated current liabilities, each as determined under our revolving credit facility, of not less than 1.0 to 1.0.
Additionally, our revolving credit facility contains various covenants and restrictive provisions that, among other things, limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of production; and prepay certain indebtedness.
Events of default under our revolving credit facility include the failure to make payments when due, breach of any covenants continuing beyond the cure period, default under any other material debt, change in management or change of control, bankruptcy or other insolvency event and certain material adverse effects on the business of OLLC or us.
If we fail to perform our obligations under these or any other covenants, the revolving credit commitments could be terminated and any outstanding indebtedness under our revolving credit facility, together with accrued interest, fees and other obligations under the credit agreement, could be declared immediately due and payable.
During the year ended December 31, 2015, the revolving credit facility was primarily used to fund the acquisitions of oil and gas properties and working capital needs. See Note 3 for additional information regarding these acquisitions.
2022 Senior Notes
On July 17, 2014, we and Finance Corp. (collectively, the “Issuers”) completed a private placement of $500.0 million aggregate principal amount of 6.875% senior unsecured notes due 2022 (the “2022 Senior Notes”). The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by the Guarantor Subsidiaries and by certain future subsidiaries of the Partnership. 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, commencing February 1, 2015. The 2022 Senior Notes are governed by an indenture and are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The Issuers may also be required to repurchase the 2022 Senior Notes upon a change of control.
The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2022 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the Issuers, all outstanding 2022 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2022 Senior Notes may declare all the 2022 Senior Notes to be due and payable immediately.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
2021 Senior Notes
On April 17, 2013, May 23, 2013 and October 10, 2013, the Issuers issued $300.0 million, $100.0 million and $300.0 million, respectively, of 7.625% senior unsecured notes due 2021 (the “2021 Senior Notes”). The 2021 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by the Guarantor Subsidiaries and by certain future subsidiaries of the Partnership. The 2021 Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes are governed by an indenture and are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The Issuers may also be required to repurchase the 2021 Senior Notes upon a change of control.
The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2021 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the Issuers or any subsidiary guarantor that is a significant subsidiary, all outstanding 2021 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2021 Senior Notes may declare all the 2021 Senior Notes to be due and payable immediately.
Previous Owner Revolving Credit Facilities
WHT, Stanolind, Boaz, Crown, Tanos and Propel and each maintained multi-year variable-rate senior secured revolving credit facilities that were primarily used for both working capital needs and to fund acquisition and development expenditures. All of Stanolind’s indebtedness outstanding under the Stanolind revolving credit facility was attributable to Stanolind SPV. Likewise, all of Propel Energy’s indebtedness outstanding under the Propel Energy revolving credit facility was attributable to Propel SPV.
On March 28, 2013, the debt balance then outstanding under the WHT revolving credit facility of $89.3 million and all accrued interest was paid off in full and the revolving credit facility was terminated. On April 1, 2013, indebtedness then outstanding under the Tanos revolving credit facility of $27.0 million was repaid and on April 25, 2013 all accrued interest was paid off in full and the revolving credit facility was terminated. On October 1, 2013, the debt balance then outstanding under the Boaz and Crown revolving credit facilities and all accrued interest was paid off in full and these revolving credit facilities were terminated. On October 1, 2013, the debt balance then outstanding under the Stanolind and Propel Energy revolving credit facilities and all accrued interest was paid off in full by the Partnership on behalf of Stanolind and Propel Energy, respectively.
All of the indebtedness outstanding under the MRD LLC revolving credit facility was attributable to Classic. On November 22, 2013, the borrowing base under this revolving credit facility was automatically reduced and triggered a mandatory principal repayment of $20.0 million. This principal repayment is reflected in previous owner equity as a contribution. On December 18, 2013, indebtedness then outstanding under the MRD LLC revolving credit facility of $59.7 million and all accrued interest was paid off in full and the revolving credit facility was terminated. This principal repayment is also reflected in previous owner equity as a contribution.
Weighted-Average Interest Rates
The following table presents the weighted-average interest rates paid on variable-rate debt obligations for the periods presented:
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Unamortized Deferred Financing Costs
Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated:
(1)
Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility.
(2)
Unamortized deferred financing costs are amortized using the straight line method which generally approximates the effective interest method.
Advances and Repayments
The following table presents borrowings and repayments under our consolidated and combined revolving credit facilities for the periods presented (in thousands):
For accounting and financial reporting purposes, any amounts that were repaid concurrent with the closing of the WHT Properties or the Cinco Group acquisition were a component of the net assets that were acquired by us and reflected on our consolidated and combined cash flow statement as “Payments on revolving credit facilities.”
Letters of credit
At December 31, 2015, we had $2.1 million of letters of credit outstanding related to our operations in Wyoming.
Note 9. Equity and Distributions
2015 Purchase of Noncontrolling Interest
In connection with the 2015 Beta Acquisition, we purchased the noncontrolling interests in SPBPC. See Note 3 for further information.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
2014 Public Equity Offerings
On September 9, 2014, we issued 14,950,000 common units representing limited partner interests in the Partnership (including 1,950,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $22.29 per unit generating total net proceeds of approximately $321.3 million after deducting underwriting discounts and offering expenses. The net proceeds from the equity offering, including our general partner’s proportionate capital contribution, were used to repay a portion of the outstanding borrowings under our revolving credit facility.
On July 15, 2014, we issued 9,890,000 common units representing limited partner interests in the Partnership (including 1,290,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the underwriters at a negotiated price of $22.25 per unit generating total net proceeds of approximately $220.0 million after deducting offering expenses. The net proceeds from the equity offering, including our general partner’s proportionate capital contribution, were used to repay a portion of the outstanding borrowings under our revolving credit facility.
2013 Public Equity Offerings
On October 8, 2013, we issued 16,675,000 common units representing limited partner interests in the Partnership (including 2,175,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $19.90 per unit generating total net proceeds of approximately $318.3 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering, including our general partner’s proportionate capital contribution, were used to repay a portion of outstanding borrowings under our revolving credit facility.
On March 25, 2013, we issued 9,775,000 common units representing limited partner interests in the Partnership (including 1,275,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $18.35 per unit generating total net proceeds of approximately $171.8 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering, including our general partner’s proportionate capital contribution, partially funded the acquisition of all of the outstanding equity interests in WHT as further discussed under Note 12.
Equity Outstanding
The following table summarizes changes in the number of outstanding units since December 31, 2012:
(1)
Restricted common units are generally net-settled by unitholders to cover the required withholding tax upon vesting. Unitholders surrendered units with value equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were $1.3 million, $1.0 million and $0.1 million for the years ended December 31, 2015, 2014 and 2013, respectively. These net-settlements had the effect of unit repurchases by the Partnership as they reduced the number of units that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Partnership.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Restricted common units are a component of common units as presented on our consolidated and combined balance sheets. See Note 11 for additional information regarding restricted common units that were granted during the years ended December 31, 2015, 2014 and 2013.
Memorial Resource owns 100% of our general partner, which owns 50% of our incentive distribution rights. The Funds collectively indirectly own 50% of our incentive distribution rights.
Common Units. The common units are a separate class of the limited partner interest in us and have limited voting rights as set forth in our partnership agreement. The holders of units are entitled to participate in partnership distributions as discussed further below under “Cash Distribution Policy” and exercise the rights or privileges available to limited partners under our partnership agreement. The subordination period ended on February 13, 2015.
On February 13, 2015, all of the 5,360,912 outstanding subordinated units owned by MRD Holdco were converted into common units. The subordinated units converted on a one-for-one basis into common units upon the payment of MEMP's fourth quarter 2014 distribution. MRD Holdco sold all of the common units during the three months ended June 30, 2015 and no longer owns any of our outstanding common units.
Pursuant to our partnership agreement, if at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a purchase price not less than the then-current market price of the common units, as calculated pursuant to the terms of our partnership agreement.
General Partner Interest and IDRs. Our general partner owns a 0.1% interest in us. Our partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, subordinated unitholders, general partner and holders of our IDRs will receive. The general partner has the management rights as set forth in our partnership agreement.
2015 Repurchases of Common Units
In December 2014, the board of directors of our general partner authorized the repurchase of up to $150.0 million of our common units (“MEMP Repurchase Program”). Under the MEMP Repurchase Program, units could be repurchased and retired from time to time at our discretion on the open market. The MEMP Repurchase Program did not obligate us to repurchase any dollar amount or specific number of common units and could have been discontinued at any time. During the year ended December 31, 2015, we repurchased $52.8 million in common units, which represents a repurchase and retirement of 3,547,921 common units under the MEMP Repurchase Program. During the year ended December 31, 2014, we repurchased $12.9 million in common units, which represented a repurchase and retirement of 899,912 common units. At December 31, 2015, we had no authorized repurchases remaining under the MEMP Repurchase Program.
Allocations of Net Income (Loss)
Net income (loss) attributable to the Partnership is allocated between our general partner and the common and subordinated 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 NGP. Net income (loss) attributable to acquisitions accounted for as a transaction between entities under common control prior to their acquisition date is allocated to the previous owners.
Cash Distribution Policy
We intend to make cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Additionally, under our revolving credit facility, we will not be able to pay distributions to unitholders in any such quarter in the event there exists a borrowing base deficiency or an event of default either before or after giving effect to such distribution or we are not in pro forma compliance with our revolving credit facility after giving effect to such distribution.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Available Cash. Our partnership agreement requires that within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2011, we distribute all of our available cash (as defined in our partnership agreement) to our general partner and unitholders of record on the applicable record date. Generally, available cash refers to all cash on hand at the end of the quarter less cash reserves established by our general partner to: (i) operate our business (e.g., future capital expenditures, working capital and operating expenses); (ii) comply with applicable law, debt, and other agreements; and (iii) provide funds for distribution to our unitholders (including our general partner) for any one or more of the next four quarters. If our general partner so determines, available cash may include borrowings made after the end of the quarter.
General Partner Interest and Incentive Distribution Rights. Our general partner is entitled to 0.1% of all distributions of available cash that we make prior to our liquidation. Our general partner’s initial 0.1% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 0.1% general partner interest. Our general partner is not obligated to contribute a proportionate amount of capital to us to maintain its current general partner interest. We have also issued IDRs, which entitle the holder(s) thereof to additional increasing percentages, up to a maximum of 24.9%, of the cash we distribute in excess of $0.54625 per common unit per quarter. Our general partner owns 50%, and the Funds indirectly own 50%, of the IDRs.
Minimum Quarterly Distribution. During the subordination period, the common units had the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4750 per common unit plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus could be made on the subordinated units. These units were deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units were not entitled to receive any distributions from operating surplus until the common units had received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages were paid on the subordinated units. The practical effect of the subordinated units was to increase the likelihood that during the subordination period there would be available cash from operating surplus to be distributed on the common units. The subordination period ended on February 13, 2015.
Our partnership agreement required that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:
·
first, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distributed for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
·
second, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distributed for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
·
third, 99.9% to the subordinated unitholders, pro rata, and 0.1% to our general partner, until we distributed for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
·
thereafter, cash in excess of the minimum quarterly distributions was distributed to the unitholders and the general partner based on the percentages in the table below.
The holders of the IDRs are entitled to incentive distributions if the amount we distribute with respect to one quarter exceeds specified target levels shown below:
(1)
The Funds collectively indirectly own 50% of our incentive distribution rights. The remaining IDRs are owned by our general partner.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period (i.e., the first quarter of 2015) in the following manner:
·
first, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
·
thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders, the general partner and the holders of the IDRs based on the percentages in the table above.
In addition, if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal, our general partner will have the right to convert its general partner units into common units or to receive cash in exchange for such general partner units at the equivalent common unit fair market value.
Our general partner has the right (but not the obligation), at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (25%, assuming it has maintained its 0.1% general partner interest) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election.
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):
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Previous Owners Capital
The following table summarizes our previous owners’ equity transactions with respect to the period indicated (dollars in thousands):
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Note 10. 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):
(1)
As a result of repurchases under the MEMP Repurchase Program, our general partner had an approximate average 0.105% interest in us for the year ended December 31, 2015.
Note 11. Equity-based Awards
Long-Term Incentive Plan
In December 2011, the Board adopted the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) for employees, officers, consultants and directors of the general partner and any of its affiliates, including Memorial Resource, who perform services for the Partnership. The LTIP consists of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights (“DERs”), other unit-based awards and unit awards. The LTIP initially limits the number of common units that may be delivered pursuant to awards under the plan to 2,142,221 common units. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The LTIP is administered by the Board or a committee thereof. During the years ended December 31, 2015, 2014 and 2013 there were multiple awards of restricted common units that were granted under the LTIP to both executive officers and independent directors of our general partners and other Memorial Resource employees.
The restricted common units awarded are subject to restrictions on transferability, customary forfeiture provisions and typically graded vesting provisions in which one-third of each award vests on the first, second, and third anniversaries of the date of grant. Award recipients have all the rights of a unitholder in the partnership with respect to the restricted common units, including the right to receive distributions thereon if and when distributions are made by the Partnership to its unitholders (except with respect to the fourth quarter 2011 distribution that was paid in February 2012). The term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires.
Based on the market price per unit on the date of grant, the aggregate fair value of the restricted common units awarded to our general partner’s executive officers and other Memorial Resource employees during the years ended December 31, 2015, 2014 and 2013 was $12.3 million, $15.0 million and $9.7 million, respectively. The restricted common units granted are accounted for as equity-classified awards. The grant-date fair value net of estimated forfeitures is recognized as compensation cost on a straight-line basis over the requisite service period. The fair value of the restricted unit awards granted to the independent directors of our general partner are also recognized as compensation cost on a straight-line basis over the requisite service period. Compensation costs are recorded as direct general and administrative expenses.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
The following table summarizes information regarding restricted common unit awards for the periods presented:
(1)
Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.
(2)
The aggregate grant date fair value of restricted common unit awards issued in 2013 was $9.9 million based on grant date market prices ranging from of $18.33 to $20.35 per unit.
(3)
The aggregate grant date fair value of restricted common unit awards issued in 2014 was $15.3 million based on grant date market prices ranging from of $21.99 to $23.40 per unit.
(4)
The aggregate grant date fair value of restricted common unit awards issued in 2015 was $12.3 million based on grant date market prices ranging from of $6.20 to $15.45 per unit.
The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands):
The unrecognized compensation cost associated with restricted common unit awards was an aggregate $16.5 million at December 31, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.8 years.
Since the restricted common units are participating securities, any distributions received by the restricted common unitholders are included in distributions to partners as presented on our statements of consolidated and combined cash flows. During the years ended December 31, 2015, 2014 and 2013, the restricted common unitholders received a distribution of approximately $2.8 million, $1.9 million and $1.0 million, respectively.
Subsequent event. On January 8, 2016, the Partnership issued a total of 155,601 phantom units to the independent directors of our general partner, which vest 100% after a one year period. Upon vesting, the phantom units will settle (i) in cash, (ii) in a number of common units equal to the number of vested units or (iii) a combination of cash and common units. The phantom unit awards also include DERs which stipulate that if there is a distribution paid on the common units, the independent directors are entitled to receive a cash payment with respect to each phantom unit equal to the cash distribution paid per unit to common unit holders.
Note 12. Related Party Transactions
Amounts payable to Memorial Resource and certain affiliates of NGP at December 31, 2015 and 2014 are presented as “Accounts payable - affiliates” in the accompanying balance sheets.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
NGP Affiliated Companies
During the year ended December 31, 2015, we paid $0.3 million to Multi-Shot, LLC, an NGP affiliated company, for services related to our drilling and completion activities.
Common Control Acquisitions
2015 Acquisition
On February 23, 2015, we and Memorial Resource completed a transaction in which we exchanged our oil and gas properties in North Louisiana and approximately $78.4 million in cash for Memorial Resource’s East Texas and Louisiana oil and gas properties. The transaction had an effective date of January 1, 2015. The properties MEMP received are primarily located in the Joaquin Field in Shelby and Panola counties in East Texas. This acquisition 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 has been retrospectively revised to give effect to such acquisition as if the Partnership owned the assets for the period after common control commenced through the acquisition date. The Partnership recorded the following net assets (in thousands):
2014 Acquisitions
On April 1, 2014, we acquired certain oil and natural gas properties in East Texas from a subsidiary of MRD LLC, for approximately $33.3 million, including customary post-closing adjustments (the “Double A Acquisition”). The acquired properties primarily represent additional working interests in wells currently owned by us and located in Polk and Tyler Counties in the Double A Field of East Texas as well as the Sunflower, Segno and Sugar Creek Fields. Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee, which is comprised entirely of independent directors. This acquisition was accounted for as a transaction with an entity under common control whereby the acquisition was recorded at historical cost at the acquisition date.
On October 1, 2014, we acquired certain oil and natural gas properties in Weld County, Colorado from Memorial Resource for approximately $15.0 million in cash consideration. The acquired properties represent working interests in wells located in the Wattenberg field (the “Wattenberg Acquisition”). Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee. This acquisition has an effective date of October 1, 2014 and was accounted for as a transaction with an entity under common control whereby the acquisition was recorded at historical cost at the acquisition date.
The Partnership recorded the following net assets (in thousands):
Due to common control considerations, the difference between the purchase price and the total identifiable assets has been recorded as a contribution on our Statements of Consolidated and Combined Equity.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
2013 Acquisitions
On March 28, 2013, we acquired all of the outstanding equity interests in WHT from operating subsidiaries of MRD LLC for a purchase price of $200.0 million, which included $4.0 million of working capital and other customary adjustments. This acquisition was funded with borrowings under our revolving credit facility and the net proceeds from our March 25, 2013 public offering of common units (including our general partner’s proportionate capital contribution). Terms of the transaction were approved by our general partner’s Board and by its conflicts committee. The WHT Properties consist of additional working interests in properties that we originally acquired in December 2011 in conjunction with our initial public offering. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands):
Acquisition of Cinco Group Properties from Memorial Resource & NGP
On October 1, 2013, we acquired, through equity and asset transactions, oil and natural gas properties primarily in the Permian Basin, East Texas and the Rockies from MRD LLC and certain affiliates of NGP for an aggregate purchase price of approximately $603 million, subject to customary post-closing adjustments. The Cinco Group acquisition was funded with borrowings under our revolving credit facility. Terms of the transaction were approved by the Board and by its conflicts committee. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands):
2015 Divestiture
On November 2, 2015, in connection with an auction process administered by a third-party, we divested certain oil and natural gas properties in the Permian Basin to an affiliate of NGP for a purchase price of approximately $0.9 million. Due to common control considerations, the proceeds from the sale exceeded the net book value of the properties sold by $0.7 million and is recognized in the equity statement.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Related Party Agreements
We and certain of our affiliates have entered into various documents and agreements. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations.
Omnibus Agreement
Memorial Resource continues to provide management, administrative and operating services for us and our general partner pursuant to our omnibus 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
In connection with the December 2012 Beta acquisition, Memorial Resource entered into a management agreement with its wholly-owned subsidiary, Beta Operating Company, LLC, pursuant to which Memorial Resource agreed to provide management and administrative oversight with respect to the services provided by such subsidiary under certain operating agreements with our subsidiary, Rise Energy Beta, LLC, related to the Beta properties in exchange for an annual management fee. Pursuant to such management agreement and in connection with such operating agreements, Memorial Resource had the right to receive approximately $0.4 million from Rise Energy Beta, LLC annually. This agreement was terminated in November 2015 in connection with the 2015 Beta Acquisition.
Cinco Group Transition Service Agreements
The Partnership entered into transition service agreements with Propel Energy, Stanolind, and Boaz Energy Partners to ensure that ownership, operation, and maintenance of acquired properties could be smoothly transitioned. The term of these agreements were from October 1, 2013 through February 28, 2014. The Partnership paid transition service fees of approximately $0.8 million in the aggregate under these agreements.
Classic Agreements
In November 2011, Classic Hydrocarbons Operating, LLC, a subsidiary of Memorial Resource (“Classic Operating”), and Classic Pipeline & Gathering, LLC (“Classic Pipeline”), a subsidiary of MRD Holdco, entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. In May 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement was terminated in November 2015 in connection with a third party’s acquisition of Classic Pipeline’s Joaquin gathering system.
In May 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement had a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline. Effective July 1, 2015, the fee was reduced to $0.40 per barrel. In February 2015, in connection with and as part of the Property Swap, Classic Hydrocarbons Holdings, L.P. sold all of the equity interests owned by it in Classic Operating as well as Craton Energy GP III, LLC (“Craton GP”) and Craton Energy Holdings III, LP (“Craton LP”), two subsidiaries of Memorial Resource, to OLLC, and Classic Operating, Craton GP and Craton LP were merged into OLLC. OLLC was therefore the successor to Classic Operating under the terminated amended gas gathering agreement and water disposal agreement.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Classic Pipeline assigned its saltwater disposal system to OLLC in November 2015. Due to common control considerations, we recorded the receipt of this asset at historical cost and recognized approximately $2.1 million in the equity statement.
For the years ended December 31, 2015, 2014 and 2013, the Partnership incurred gathering and salt water disposal fees of approximately $3.2 million, $1.8 million and $0.6 million, respectively, from Classic Pipeline, an affiliate.
Other Related Party Transactions
Director & Advisory Fees
Certain of the Cinco Group entities entered into an advisory service, reimbursement, and indemnification agreements with NGP. These agreements generally required that an annual advisory fee be paid to NGP. Fees paid under these agreements for the year ended December 31, 2013 were approximately $0.3 million.
Classic Management Team Equity Interest
On November 1, 2013, Classic’s management team sold its membership interest in Classic to MRD LLC and all incentive units held were forfeited.
The governing documents of Classic provided for the issuance of incentive units. Classic granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units were entitled to distributions when declared, but only after cumulative distribution thresholds had been achieved (i.e., recovery of specified members’ capital contributions plus a rate of return). These incentive units were accounted for as liability awards with compensation expense based on period-end fair value. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. No compensation cost was recorded related to incentive units prior to the incentive units being forfeited on November 1, 2013. Compensation expense of approximately $8.3 million was recorded by Classic and recognized as general and administrative expense during November 2013.
Tanos Management Team Equity Interest
On April 1, 2013, Tanos’ management team sold its 1.066% membership interest in Tanos to MRD LLC and all incentive units held were forfeited. In connection with this sale, all of Tanos’ employees resigned and became employees of Tanos Exploration II, LLC (“Tanos II”), a Texas limited liability company controlled by the former management team of Tanos. Effective April 1, 2013, Tanos II entered into a Transition Services Agreement with Tanos, whereby Tanos II would manage the operations of Tanos for up to a 6-month period of time. Tanos II is an unrelated entity.
The governing documents of Tanos provided for the issuance of incentive units. Tanos granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units were entitled to distributions when declared, but only after cumulative distribution thresholds had been achieved (i.e., recovery of specified members’ capital contributions plus a rate of return). These incentive units were accounted for as liability awards with compensation expense based on period-end fair value. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. No compensation cost was recorded related to incentive units prior to the incentive units being forfeited on April 1, 2013. Compensation expense of approximately $5.8 million was recorded by Tanos and recognized as general and administrative expense during April 2013.
Note 13. Commitments and Contingencies
Litigation & Environmental
As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings. We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. At December 31, 2015, none of our estimated environmental remediation liabilities were discounted to present value since the ultimate amount and timing of cash payments for such liabilities were not readily determinable.
The following table presents the activity of our environmental reserves for the periods presented:
At December 31, 2015 and 2014, $0.2 million and $2.1 million, respectively, of our environmental reserves were classified as current liabilities in accrued liabilities.
Sinking Fund Trust Agreement
REO assumed an obligation with a third party to make payments into a sinking fund in connection with its 2009 acquisition of the Beta properties, the purpose of which is to provide funds adequate to decommission the portion of the San Pedro Bay pipeline that lies within State waters and the surface facilities. Under the terms of the agreement, REO, as the operator of the properties, is obligated to make monthly deposits into the sinking fund account in an amount equal to $0.25 per barrel of oil and other liquid hydrocarbon produced from the acquired working interest. Interest earned in the account stays in the account. The obligation to fund ceases when the aggregate value of the account reaches $4.3 million. As of December 31, 2015, the gross account balance included in restricted investments was approximately $3.2 million.
Supplemental Bond for Decommissioning Liabilities Trust Agreement
REO assumed an obligation with the BOEM in connection with its 2009 acquisition of the Beta properties. Under the terms of the agreement dated March 1, 2007, the seller of the Beta properties was obligated to deliver a $90.0 million U.S. Treasury Note into a trust account for the decommissioning of the offshore production facilities. At the time of acquisition, all obligations under this existing agreement had been met.
In January 2010, the BOEM issued a report that revised upward, the estimated cost of decommissioning. In June 2010, REO agreed to make additional quarterly payments to the trust account of $1.25 million. The trust account must maintain minimum balances as follows (in thousands):
In the event the account balance is less than the contractual amount, the working interest owners 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 the working interest owners. As of December 31, 2015, the remaining obligation was approximately $8.0 million. In 2015, the BOEM issued a preliminary report that indicated the estimated cost of decommissioning may further increase, and we expect the amount to be finalized during 2016 after negotiations are completed.
The gross held-to-maturity investments held in the trust account as of December 31, 2015 for the U.S. Bank money market cash equivalent was $144.0 million.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Operating Leases
We have leases for offshore Southern California pipeline right-of-way use as well as office space in our operating regions. We also lease equipment, compressors and incur surface rentals related to our business operations. The previous owners also leased equipment and office space under various operating leases and incurred surface rentals related to their operations.
For the years ended December 31, 2015, 2014 and 2013, we recognized $16.9 million, $6.4 million and $2.4 million of rent expense, respectively. The previous owners recorded rent expense of approximately $0.5 million and $2.9 million for the years ended December 31, 2014 and 2013, respectively.
Amounts shown in the following table represent minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year (in thousands):
Purchase Commitments
At December 31, 2015, we had a CO2 purchase commitment with a third party associated with our Wyoming Bairoil properties and purchase commitments related to our Beta properties. The table below outlines our purchase commitments under these contracts (in thousands):
Minimum Volume Commitment
At December 31, 2015, we had a seven year minimum volume commitment with a third party associated with a certain portion of our properties located in East Texas. The table below outlines the payment commitments associated with this minimum volume commitment (in thousands):
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Note 14. Income Tax
The components of income tax benefit (expense) are as follows:
The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 35% as follows:
(1)
MEMP, a publicly traded partnership with qualifying income, is a pass-through entity for federal income tax purposes.
The components of net deferred income tax liabilities recognized were as follows:
A deferred tax liability was recorded in equity by the previous owners and related to Memorial Resource’s initial public offering and restructuring transactions as it represented a transaction among shareholders. Subsequent to the Memorial Resource’s initial public offering, income tax related to the Property Swap was calculated on a separate return basis.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Uncertain Income Tax Position. We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. We had no unrecognized tax benefits as of December 31, 2015 or 2014.
Tax Audits and Settlements. Generally, our income tax years 2011 through 2015 remain open and subject to examination by the Internal Revenue Service or state tax jurisdictions where we conduct operations. In certain jurisdictions we operate through more than one legal entity, each of which may have different open years subject to examination.
Tax Attribute carryforwards and Valuation Allowance. As of December 31, 2015, we had federal net operating loss carryforwards of approximately $0.2 million, which would expire in 2034. No valuation allowance was established based upon management’s evaluation that loss carryforwards will be fully realized.
Note 15. Quarterly Financial Information (Unaudited)
The following tables present selected quarterly financial data for the periods indicated. Earnings per unit are computed independently for each of the quarters presented and the sum of the quarterly earnings per unit may not necessarily equal the total for the year.
The Partnership has consummated several common control acquisitions, as further discussed in Note 12, directly or indirectly from Memorial Resource and certain affiliates of NGP. The quarterly financial information for the years ended December 31, 2015 and 2014 presented above has been retrospectively revised for the Property Swap. See Notes 2 and 10 for additional information regarding earnings per unit.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Note 16. Supplemental Oil and Gas Information (Unaudited)
Capitalized Costs Relating to Oil and Natural Gas Producing Activities
The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated.
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated:
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Partnership’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.
Oil and Natural Gas Reserves
Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
We engaged Ryder Scott to audit our reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2015. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.
The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented:
(1)
The weighted average WTI price was adjusted by lease for quality, transportation fees, and a regional price differential.
(2)
The weighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.
The following tables set forth estimates of the net reserves as of December 31, 2015, 2014 and 2013, respectively:
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Noteworthy amounts included in the categories of proved reserve changes in the above tables include:
·
We acquired 561.7 Bcfe in multiple acquisitions during the year ended December 31, 2014, the largest being the Wyoming Acquisition of 497.2 Bcfe. We also acquired 45.0 Bcfe from the Eagle Ford Acquisition. An upward revision of natural gas for the year ended December 31, 2014 was due to increased natural gas prices on certain East Texas properties. The upward revision was partially offset by a downward revision of natural gas for the year ended December 31, 2014, which was primarily due to updated well performance data in certain other East Texas fields. Proved undeveloped reserves increased during the year ended December 31, 2014 primarily due to the Wyoming Acquisition.
·
The 415.4 Bcfe reduction in reserves for the year ended December 31, 2015 is primarily due to a 413 Bcfe downward pricing revision and a 13 Bcfe downward revision due to updated well performance data. We acquired 97.1 Bcfe during the year ended December 31, 2015, the largest being the 2015 Beta Acquisition of 58.5 Bcfe. Proved undeveloped reserves decreased primarily due to downward pricing during the year ended December 31, 2015.
See Note 3 for additional information on acquisitions and divestitures.
A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.
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MEMORIAL PRODUCTION PARTNERS LP
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
The standardized measure of discounted future net cash flows is as follows:
(1)
We are subject to the Texas margin tax based on the taxable margin apportioned to Texas. However, due to immateriality we have excluded the impact of this tax for the years ended December 31, 2015, 2014 and 2013. The 2014 amount was related to Classic since its reserves were a part of a taxable entity for federal income tax purposes for the year ended December 31, 2014.
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2015:
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Exhibit Index
*
Filed or furnished as an exhibit to this Annual Report on Form 10-K.
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Management contract or compensatory plan or arrangement.
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Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.