10-K 1 memp-10k_20161231.htm 10-K memp-10k_20161231.htm

 

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10–K

 

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

 

For the fiscal year ended December 31, 2016

 

OR

 

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

 

For the transition period from                      to                     .

 

Commission File Number: 001-35364

 

MEMORIAL PRODUCTION PARTNERS LP

(Exact name of registrant as specified in its charter)

 

Delaware

 

90-0726667

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification No.)

 

500 Dallas Street, Suite 1600, Houston, TX

 

77002

(Address of principal executive offices)

 

(Zip Code)

 

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

Securities registered pursuant to Section 12(b) of the Act:

 

 

 

The NASDAQ Stock Market LLC

Common Units Representing Limited Partner Interests

 

(NASDAQ Global Market)

(Title of each class)

 

(Name of each exchange on which registered)

 

Securities registered pursuant to Section 12(g) of the Act: None

 

 

 

Indicate by check mark if the registrant is a well–known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes      No      

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes      No  

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S–K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III or any amendment to the Form 10–K  

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

 Large accelerated filer

 

 

  

Accelerated filer

 

 

 

 

 

Non-accelerated filer

 

  (Do not check if a smaller reporting company)

  

Smaller reporting company

 

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

The aggregate market value of the common units held by non-affiliates was approximately $166.5 million on June 30, 2016, the last business day of the registrant’s most recently completed second fiscal quarter, based on closing prices in the daily composite list for transactions on the NASDAQ Global Market on such date. As of March 3, 2017, the registrant had 83,804,848 common units outstanding.

Documents Incorporated By Reference: None

 


MEMORIAL PRODUCTION PARTNERS LP

TABLE OF CONTENTS

 

 

 

 

  

Page

 

 

 

PART I

  

 

Item 1.

 

Business

  

9

Item 1A.

 

Risk Factors

  

33

Item 1B.

 

Unresolved Staff Comments

  

59

Item 2.

 

Properties

  

59

Item 3.

 

Legal Proceedings

  

60

Item 4.

 

Mine Safety Disclosures

  

60

 

 

 

PART II

  

 

Item 5.

 

Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

  

61

Item 6.

 

Selected Financial Data

  

63

Item 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

  

65

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

  

83

Item 8.

 

Financial Statements and Supplementary Data

  

85

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

  

86

Item 9A.

 

Controls and Procedures

  

86

Item 9B.

 

Other Information

  

88

 

 

 

PART III

  

 

Item 10.

 

Directors, Executive Officers and Corporate Governance

  

89

Item 11.

 

Executive Compensation

  

94

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

  

104

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

  

104

Item 14.

 

Principal Accountant Fees and Services

  

107

 

 

 

PART IV

  

 

Item 15.

 

Exhibits and Financial Statement Schedules

  

108

Item 16.

 

Form 10-K Summary

 

108

 

Signatures

  

109

 

 

 

 


GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

Basin: A large depression on the earth’s surface in which sediments accumulate.

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

Bbl/d: One Bbl per day.

Bcf: One billion cubic feet of natural gas.

Bcfe: One billion cubic feet of natural gas equivalent.

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

Boe/d: One Boe per day.

BOEM: Bureau of Ocean Energy Management.

BSEE: Bureau of Safety and Environmental Enforcement.

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

Deterministic Estimate: The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation is used in the reserves estimation procedure.

Developed Acreage: The number of acres which are allocated or assignable to producing wells or wells capable of production.

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

Development Well: A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential: An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

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

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

Estimated Ultimate Recovery: Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

1


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

Exploratory Well: A well drilled to find and produce oil and natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

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

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

ICE: Inter-Continental Exchange.

MBbl: One thousand Bbls.

MBbls/d: One thousand Bbls per day.

MBoe: One thousand Boe.

MBoe/d: One thousand Boe per day.

MBtu: One thousand Btu.

MBtu/d: One thousand Btu per day.

Mcf: One thousand cubic feet of natural gas.

Mcf/d: One Mcf per day.

MMBtu: One million British thermal units.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

Net Acres or Net Wells: Gross acres or wells, as the case may be, multiplied by our working interest ownership percentage.

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

Net Revenue Interest: A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.

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

NYMEX: New York Mercantile Exchange.

Oil: Oil and condensate.

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

OPIS: Oil Price Information Service.

Play: A geographic area with hydrocarbon potential.

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

2


Productive Well: A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.

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

Proved Reserve Additions: The sum of additions to proved reserves from extensions, discoveries, improved recovery, acquisitions and revisions of previous estimates.

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

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

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

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

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

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

3


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

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

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

Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.

Spot Price: The cash market price without reduction for expected quality, transportation and demand adjustments.

Standardized Measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or standards established by the United States Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”) (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

Undeveloped Acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

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

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

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

WTI: West Texas Intermediate.

4


NAMES OF ENTITIES

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

 

“Memorial Production Partners,” “the Partnership,” “we,” “our,” “us” or like terms refer to Memorial Production Partners LP individually and collectively its subsidiaries, as the context requires;

 

“our general partner” and “MEMP GP” refers to Memorial Production Partners GP LLC, our general partner and wholly-owned subsidiary;

 

“Memorial Resource” refers to Memorial Resource Development Corp., the former owner of our general partner;

 

“MRD LLC” refers to Memorial Resource Development LLC, which is the predecessor of Memorial Resource;

 

“Cinco Group” refers to (i) certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies owned by: (a) Boaz Energy, LLC (“Boaz”), (b) Crown Energy Partners, LLC (“Crown”), (c) the Crown net profits overriding royalty interest and overriding royalty interest (“Crown NPI/ORRI”), (d) Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), (e) Stanolind Oil and Gas SPV LLC (“Stanolind SPV”), (f) Tanos Energy, LLC (“Tanos”), together with its wholly-owned subsidiaries, and (g) Prospect Energy, LLC (“Prospect”) and (ii) certain oil and natural gas properties in Jackson County, Texas (the “MRD Assets”) owned by Memorial Resource. The Partnership acquired substantially all of the Cinco Group on October 1, 2013 from: (x) 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 were primarily owned by two of the Funds (defined below) and (y) MRD LLC;

 

“the previous owners” for accounting and financial reporting purposes refers collectively to: (a) certain oil and natural gas properties the Partnership acquired from MRD LLC in April and May 2012 (“Tanos/Classic Properties”) for periods after common control commenced through their respective acquisition dates, (b) Rise Energy Operating, LLC and its wholly-owned subsidiaries (except for Rise Energy Operating, Inc.) (“REO”) from February 3, 2009 (inception) through the date of acquisition, (c) certain oil and natural gas properties and related assets in East Texas and North Louisiana that the Partnership acquired in March 2013 (the “WHT Properties”) owned by WHT Energy Partners LLC (“WHT”) from February 2, 2011 (inception) through the date of acquisition, (d) the Cinco Group, and (e) certain oil and gas properties primarily located in the Joaquin Field in Shelby and Panola counties in East Texas and in Louisiana acquired from Memorial Resource in February 2015 (“Property Swap”) for periods after common control commenced through the date of acquisition;

 

“the Funds” refers collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively control MRD Holdco;

 

“OLLC” refers to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties;

 

“Finance Corp.” refers 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;

 

“MRD Holdco” refers to MRD Holdco LLC, which together with a group controlled Memorial Resource; and

 

“NGP” refers to Natural Gas Partners.

 

5


FORWARD–LOOKING STATEMENTS

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

 

bankruptcy proceedings and the effect of those proceedings on our ongoing and future operations;

 

business strategies, including our business strategies post-emergence from bankruptcy;

 

cash flows and liquidity;

 

financial strategy;

 

ability to replace the reserves we produce through drilling and property acquisitions;

 

drilling locations;

 

oil and natural gas reserves;

 

technology;

 

realized oil, natural gas and NGL prices;

 

production volumes;

 

lease operating expenses;

 

gathering, processing, and transportation;

 

general and administrative expenses;

 

future operating results;

 

ability to procure drilling and production equipment;

 

ability to procure oil field labor;

 

planned capital expenditures and the availability of capital resources to fund capital expenditures;

 

ability to access capital markets;

 

marketing of oil, natural gas and NGLs;

 

expectations regarding general economic conditions;

 

competition in the oil and natural gas industry;

 

effectiveness of risk management activities;

 

environmental liabilities;

 

counterparty credit risk;

 

expectations regarding governmental regulation and taxation;

 

expectations regarding distributions and distribution rates;

 

expectations regarding developments in oil-producing and natural-gas producing countries; and

 

plans, objectives, expectations and intentions.

6


All statements, other than statements of historical fact, included in this report are forward-looking statements. These forward-looking statements may be found in “Item 1. Business,” “Item 1A. Risk Factors,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other sections of this report. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “outlook,” “continue,” the negative of such terms or other comparable terminology. These statements address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as projections of results of operations, plans for growth, goals, future capital expenditures, competitive strengths, references to future intentions and other such references.  These forward-looking statements involve risks and uncertainties. Important factors that could cause our actual results or financial condition to differ materially from those expressed or implied by forward-looking statements include, but are not limited to, the following risks and uncertainties:

 

our expectations regarding the outcome of our bankruptcy proceedings, including our ability to confirm our plan of reorganization and emerge from bankruptcy;

 

our future cash flows and their adequacy to fund the costs of our bankruptcy proceedings and our ongoing operations;

 

our plan of reorganization filed in connection with our bankruptcy proceedings;

 

our inability to maintain relationships with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing;

 

our indebtedness and our ability to satisfy our debt obligations and a potential inability to effect deleveraging transactions or otherwise reduce those risks;

 

our ability to access funds on acceptable terms, if at all, because of the terms and conditions governing our indebtedness;

 

ability to resume payment of distributions in the future or maintain or grow them after such resumption;

 

volatility in the prices for oil, natural gas, and NGLs, including further or sustained declines in commodity prices;

 

the potential for additional impairments due to continuing or future declines in oil, natural gas and NGL prices;

 

the uncertainty inherent in estimating quantities of oil, natural gas and NGLs reserves;

 

our substantial future capital requirements, which may be subject to limited availability of financing;

 

the uncertainty inherent in the development and production of oil and natural gas;

 

our need to make accretive acquisitions or substantial capital expenditures to maintain our declining asset base;

 

the existence of unanticipated liabilities or problems relating to acquired or divested businesses or properties;

 

potential acquisitions, including our ability to make acquisitions on favorable terms or to integrate acquired properties;

 

the consequences of changes we have made, or may make from time to time in the future, to our capital expenditure budget, including the impact of those changes on our production levels, reserves, results of operations and liquidity;

 

potential shortages of, or increased costs for, drilling and production equipment and supply materials for production, such as CO2;

 

potential difficulties in the marketing of oil and natural gas;

 

changes to the financial condition of counterparties;

 

uncertainties surrounding the success of our secondary and tertiary recovery efforts;

 

competition in the oil and natural gas industry;

 

general political and economic conditions, globally and in the jurisdictions in which we operate;

 

the impact of legislation and governmental regulations, including those related to climate change, hydraulic fracturing and our status as a partnership for federal income tax purposes;

 

the risk that our hedging strategy may be ineffective or may reduce our income;

 

the cost and availability of insurance as well as operating risks that may not be covered by an effective indemnity or insurance;

 

actions of third-party co-owners of interest in properties in which we also own an interest; and

 

other risks and uncertainties described in “Item 1A. Risk Factors.”

7


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

 

 

8


PART I

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 wholly-owned by its limited partners. Our general partner, which owns a non-economic general partner interest in us, is responsible for managing all of the Partnership’s operations and activities.

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our business activities are conducted through OLLC, our wholly-owned subsidiary, and its wholly-owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, Wyoming and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs with well-known geologic characteristics and long-lived, predictable production profiles and modest capital requirements. As of December 31, 2016:

 

Our total estimated proved reserves were approximately 916.6 Bcfe, of which approximately 43% were oil and 73% were classified as proved developed reserves;

 

We produced from 2,497 gross (1,488 net) producing wells across our properties, with an average working interest of 60%, and the Partnership is the operator of record of the properties containing 94% of our total estimated proved reserves; and

 

Our average net production for the three months ended December 31, 2016 was 205.5 MMcfe/d, implying a reserve-to-production ratio of approximately 12 years.

Bankruptcy Proceedings under Chapter 11

On January 16, 2017, the Partnership and certain of its subsidiaries (collectively with the Partnership, the “Debtors”) filed voluntary petitions (the cases commenced thereby, the “Chapter 11 proceedings”) under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code” or “Chapter 11”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”) to pursue a Joint Chapter 11 Plan of Reorganization for the Debtors (as proposed, the “Plan”), which was filed contemporaneously with the Debtors’ voluntary petitions. The Debtors’ Chapter 11 proceedings are being jointly administered under the caption In re Memorial Production Partners LP, et al. (Case No. 17-30262). The Bankruptcy Court has granted all of the first day motions filed by the Debtors, which were designed primarily to minimize the impact of the Chapter 11 proceedings on the Partnership’s operations, customers and employees. The Debtors will continue to operate their businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The Partnership expects to continue its operations without interruption during the pendency of the Chapter 11 proceedings. See Note 2 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information.

For the duration of and after the Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to risks and uncertainties associated with Chapter 11 proceedings. These risks include the risks described in Item 1A, “Risk Factors.” As a result of these risks and uncertainties, our assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this annual report may not accurately reflect our operations, properties and capital plans following the Chapter 11 proceedings.

2016 and 2017 Developments – Debt Instruments

Throughout 2016, the Partnership, along with its legal and financial advisors, explored various strategic alternatives with a focus on liquidity and financial flexibility. The Partnership specifically evaluated options with the lenders under our revolving credit facility, dated as of December 14, 2011 (as the context may require, as amended, supplemented or otherwise modified, the “Credit Agreement” or “revolving credit facility”), by and among the Partnership, OLLC, the administrative agent and the other agents and lenders party thereto, and holders of the Partnership’s senior notes that would improve liquidity and deleverage the Partnership.

In April 2016, in connection with the semi-annual borrowing base redetermination by the lenders under our revolving credit facility, the borrowing base under our revolving credit facility was reduced from $1,175.0 million to $925.0 million. Our revolving credit facility was also amended pursuant to the tenth amendment to the Credit Agreement dated as of April 14, 2016, which, among other things, added additional financial restrictions and covenants under the Credit Agreement.

In October 2016, in connection with the second semi-annual borrowing base redetermination, the borrowing base under our revolving credit facility was reduced to $740.0 million and a further reduction of the borrowing base to $720.0 million was scheduled for December 1, 2016 in accordance with the terms of the eleventh amendment to Credit Agreement dated as of October 28, 2016.

9


In November 2016, we elected to defer an approximately $24.6 million interest payment due on November 1, 2016 with respect to our 7.625% senior notes due May 2021 (“2021 Senior Notes”). The interest payment was subject to a 30-day grace period under the indenture. Failure to pay such interest payment on November 1, 2016 would have resulted in certain defaults and events of default under our revolving credit facility. The lenders under the revolving credit facility, on November 1, 2016, waived such defaults and events of default through November 30, 2016 (such period from November 1, 2016 to November 31, 2016, the “Waiver Period”), in each case, subject to the terms and conditions set forth in the limited waiver and twelfth amendment (the “Waiver and Twelfth Amendment”) to our revolving credit facility.

On November 30, 2016, the Partnership, OLLC, certain subsidiaries of the Partnership, the administrative agent, and the lenders consenting thereto entered into the first amendment to the limited waiver under our revolving credit facility, extending the Waiver Period to December 16, 2016.

On November 30, 2016, the Partnership entered into forbearance agreements with certain noteholders that held approximately 51.7% of the 2021 Senior Notes and 69% of the Partnership’s 6.875% senior notes due August 2022 (“2022 Senior Notes”). Under the forbearance agreements, the noteholders agreed to forbear from exercising any and all remedies available to them as a result of the Partnership’s election not to make an interest payment of $24.6 million due on the 2021 Senior Notes. The forbearance agreements initially extended through December 7, 2016, and were subsequently extended through December 16, 2016.

On December 16, 2016, the Partnership, OLLC, certain subsidiaries of the Partnership, the administrative agent, and the lenders consenting thereto entered into the second amendment to limited waiver under our revolving credit facility, extending the Waiver Period to January 13, 2017. In addition, the forbearance agreements were extended through January 13, 2017.

In December 2016, pursuant to the second amendment to the limited waiver, the Partnership monetized certain hedge positions and used the cash proceeds to repay outstanding borrowings under our revolving credit facility. In conjunction with the hedge monetization, our borrowing base was reduced from $720.0 million to $619.0 million on December 21, 2016 and then further reduced to $530.7 million on December 22, 2016.

On December 22, 2016, the Partnership entered into a Plan Support Agreement (the “Noteholder PSA”) with holders of over an aggregate of 50.2% of the aggregate outstanding principal amount of the 2021 Senior Notes and the 2022 Senior Notes (collectively, the “Notes”), as well as reached an agreement-in-principle with the administrative agent under our revolving credit facility on the terms of a financial restructuring. Under the terms of the Noteholder PSA, the financial restructuring would be effected through the Plan. Pursuant to the terms of the Plan, which would be subject to approval of the Bankruptcy Court, it is anticipated that, among other things, on the effective date of the Plan (the “Effective Date”):

 

A newly formed corporation, as successor to the Partnership (“Reorganized Memorial”) would issue (i) new common shares (the “New Common Shares”) and (ii) five year warrants (the “Warrants”) entitling their holders upon exercise thereof, on a pro rata basis, to 8% of the total issued and outstanding New Common Shares, at a per share exercise price equal to the principal and accrued interest on the senior notes as of December 31, 2016, divided by the number of issued and outstanding New Common Shares (including New Common Shares issuable upon exercise of the Warrants), which New Common Shares and Warrants will be distributed as set forth below;

 

The Notes would be cancelled and discharged and the holders of those Notes would receive (directly or indirectly) New Common Shares representing, in the aggregate, 98% of the New Common Shares issued on the Effective Date (subject to dilution by the post-emergence management incentive plan and the New Common Shares issuable upon exercise of the Warrants);

 

The noteholders, at their election, would be entitled to receive an additional cash payment of up to approximately $24.6 million;

 

Each holder of existing equity interests in the Partnership would receive its pro rata share of (i) New Common Shares representing, in the aggregate, 2% of the New Common Shares issued on the Effective Date and (ii) the Warrants (in each case, subject to dilution by the post-emergence management incentive plan and, in the case of the New Common Shares, subject to dilution by the Warrants);

 

General unsecured claims, on or after the effective date, would be paid in the ordinary course; and

 

Reorganized Memorial would enter into an exit credit facility in the form of an amendment and restatement of the existing revolving credit facility (the “Exit Credit Facility”).

The restructuring transactions pursuant to the Plan are intended to be structured in a manner that minimizes, to the extent possible, the negative tax impact of cancellation-of-debt income to the Partnership’s existing unitholders. The Partnership expects to emerge from the Chapter 11 proceedings as a corporation, including for U.S. federal income tax purposes.

In January 2017, we monetized certain hedge positions and used a portion of the cash proceeds to repay outstanding borrowings under our revolving credit facility and kept the remaining portion as cash on hand for general partnership purposes. In conjunction with the hedge monetization, our borrowing base was reduced to $457.2 million on January 13, 2017.

10


On January 13, 2017, the Partnership entered into the third amendment to limited waiver, which extended the outside date of the Waiver Period from January 13, 2017 to January 16, 2017. In addition, the Partnership entered into a Plan Support Agreement (the “RBL PSA”) with lenders holding 100% of the loans under our revolving credit facility. The RBL PSA was entered into on terms substantially similar to those of the Noteholder PSA. In addition, among other things, the RBL PSA provided that (i) the consenting lenders (as defined in the RBL PSA) may terminate the RBL PSA upon the termination of the Noteholder PSA or if there is an amendment to the Noteholder PSA that is, or would reasonably be expected to be, adverse to the administrative agent under our revolving credit facility or the consenting lenders and (ii) each of the Debtors agreed to not file a voluntary petition for relief under Chapter 11 until the Debtors terminated certain swap agreements identified in the RBL PSA and used the net proceeds thereof to repay outstanding amounts under the revolving credit facility.  

An indicative summary of the expected terms and conditions of the Exit Credit Facility is set forth in an annex to the RBL PSA filed with our Current Report on Form 8-K filed with the SEC on January 17, 2017, which terms and conditions may include (but are not limited to) the following:

 

senior secured revolving credit facility with maximum aggregate commitments of $1 billion, subject to a borrowing base;

 

an expected initial borrowing base of approximately $474.0 to $492.5 million based on a April emergence date to be effective upon consummation of the restructuring transactions, subject to an amortization schedule thereafter until November 1, 2017;

 

the first scheduled borrowing base redetermination will occur on November 1, 2017 and thereafter, each April 1st and October 1st;

 

a maturity date of March 19, 2021;

 

an ongoing covenant requiring that we grant a security interest in substantially all of our personal and real property and that we mortgage, in each case as collateral for the obligations under the Exit Credit Facility, oil and gas properties representing not less than 95% of the total value of our oil and gas properties evaluated in the most recently completed reserve report;

 

the loans under the Exit Credit Facility shall bear interest at a rate per annum equal to the base rate or LIBOR/Eurodollar rate plus an applicable margin that ranges from 2.00% to 3.00% per annum (based on borrowing base usage) on alternate base rate loans and from 3.00% to 4.00% per annum (based on borrowing base usage) on LIBOR/Eurodollar loans;

 

the loan commitments under the Exit Credit Facility are subject to a commitment fee on the unused portion of the borrowing base at a rate per annum equal to 0.50%;

 

customary mandatory prepayments as well a requirement that, in the event that as of the close of any business day the aggregate amount of our unrestricted cash and cash equivalents exceeds $35.0 million in the aggregate, we must prepay the loans under the Exit Credit Facility (without a corresponding reduction in the available commitments under the Exit Credit Facility) and cash-collateralize any letter of credit exposure in an amount equal to such excess; provided that, we may elect to increase such the excess cash threshold from $35.0 million to $50.0 million at such time as the aggregate amount of net cash proceeds received from asset sales exceeds the borrowing base value attributable to such assets (if any) equals or exceeds $15.0 million; provided further, however, that in the event that we issue certain unsecured debt in an aggregate amount of $10.0 million or greater, we will no longer have the ability to increase such threshold above $35.0 million and, if such threshold is greater than $35.0 million at such time, such threshold will be immediately reduced to $35.0 million;

 

financial covenants, requiring that we maintain a ratio of (i) consolidated EBITDAX (to be defined in the Exit Credit Facility) for the four fiscal quarter period then ending to consolidated net interest expense for such period of not less than 2.50 to 1.00, which we refer to as the interest coverage ratio, (ii) consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0; and (iii) consolidated total debt as of such time to consolidated EBITDAX for the four fiscal quarter period then ending on such day of not greater than 4.0 to 1.0;

 

a requirement that we hedge no less than 50% of our forecasted proved developed producing production through 2019 on or prior to December 31, 2017; and

 

the representations and warranties, affirmative covenants, negative covenants, events of default and other restrictive provisions will be substantially consistent with our current revolving credit facility, subject to certain exceptions and a provision permitting us, under specified and limited circumstances, to incur additional unsecured indebtedness in an original aggregate principal amount not to exceed $80.0 million.

See Note 9 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our debt instruments.

11


Notice of Delisting

On January 17, 2017, the Partnership received a letter from the Listing Qualifications Department of The NASDAQ Stock Market LLC (“NASDAQ”) notifying the Partnership that (1) as a result of the Chapter 11 proceedings, and in accordance with NASDAQ Listing Rules 5101, 5110(b) and IM-5101-1, NASDAQ had determined that the Partnership’s common units would be delisted from NASDAQ and (2) accordingly, unless the Partnership requested an appeal of this determination, trading of the common units would have been suspended at the opening of business on January 26, 2017 and the Partnership’s securities would have been removed from listing and registration on NASDAQ. The Partnership has appealed this determination. See Note 2 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information.

Other 2016 Developments

Suspension of Quarterly Cash Distribution

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

Leadership Changes

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

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

Divestitures

In July 2016, we closed a transaction to divest certain assets located in Colorado and Wyoming (the “Rockies Divestiture”) for a total purchase price of approximately $16.4 million, including final post-closing adjustments. In June 2016, we closed a transaction to divest assets located in the Permian Basin (the “Permian Divestiture”) for a total purchase price of approximately $36.7 million, including estimated post-closing adjustments. The proceeds from the divestitures were used to reduce borrowings under our revolving credit facility.

MEMP GP Acquisition

In June 2016, the Partnership acquired all of the equity interests in MEMP GP from Memorial Resource (the “MEMP GP Acquisition”) for cash consideration of approximately $0.8 million. See “—Our Principal Business Relationships” below for additional information regarding such acquisition.

Repurchase of Senior Notes

During the year ended December 31, 2016, the Partnership repurchased an aggregate principal amount of approximately $53.7 million of the 2021 Senior Notes at a weighted average price of 49.09% of the face value of the 2021 Senior Notes. During the year ended December 31, 2016, the Partnership repurchased an aggregate principal amount of approximately $32.0 million of the 2022 Senior Notes at a weighted average price of 46.50% of the face value of the 2022 Senior Notes.

12


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, 2016. 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, 2016 and our average net production for the three months ended December 31, 2016:

 

 

 

Estimated Net Proved Reserves

 

 

 

 

 

 

Average Net Production

 

 

Average

 

 

Producing Wells

 

 

 

 

 

 

 

% Oil and

 

 

% Natural

 

 

% Proved

 

 

Standardized

 

 

 

 

 

 

% of

 

 

Reserve-to-Production

 

 

 

 

 

 

 

 

 

Region

 

Bcfe (1)

 

 

NGL

 

 

Gas

 

 

Developed

 

 

Measure (2)

 

 

MMcfe/d

 

 

Total

 

 

Ratio (3)

 

 

Gross

 

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(in millions)

 

 

 

 

 

 

 

 

 

 

(Years)

 

 

 

 

 

 

 

 

 

East Texas/Louisiana

 

 

432

 

 

 

28%

 

 

 

72%

 

 

 

72%

 

 

$

194

 

 

 

128.7

 

 

 

63%

 

 

 

9.2

 

 

 

1,605

 

 

 

905

 

Rockies

 

 

221

 

 

 

100%

 

 

 

0%

 

 

 

78%

 

 

 

72

 

 

 

28.3

 

 

 

14%

 

 

 

21.4

 

 

 

116

 

 

 

116

 

California

 

 

176

 

 

 

100%

 

 

 

0%

 

 

 

61%

 

 

 

84

 

 

 

24.3

 

 

 

12%

 

 

 

19.8

 

 

 

52

 

 

 

52

 

South Texas

 

 

88

 

 

 

33%

 

 

 

67%

 

 

 

87%

 

 

 

46

 

 

 

24.2

 

 

 

11%

 

 

 

10.0

 

 

 

724

 

 

 

415

 

Total

 

 

917

 

 

 

60%

 

 

 

40%

 

 

 

73%

 

 

$

396

 

 

 

205.5

 

 

 

100%

 

 

 

12.2

 

 

 

2,497

 

 

 

1,488

 

 

(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 $42.75/Bbl for crude oil and NGLs and $2.48/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, 2016 by the annualized average net production for the three months ended December 31, 2016.

Our Principal Business Relationships

On April 27, 2016, the Partnership entered into an agreement pursuant to which we agreed to acquire, among other things, all of the equity interests in our general partner, MEMP GP, from Memorial Resource for cash consideration of approximately $0.8 million. MEMP GP held an approximate 0.1% general partner interest and 50% of the incentive distribution rights ("IDRs") in us. In conjunction with the MEMP GP Acquisition, on April 27, 2016, we also entered into an agreement with an NGP affiliate pursuant to which we agreed to acquire the other 50% of the IDRs.

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

Our Areas of Operation

East Texas/Louisiana

Approximately 47% of our estimated proved reserves as of December 31, 2016 and approximately 63% of our average daily net production for the three months ended December 31, 2016 were located in the East Texas/Louisiana region. Our East Texas/Louisiana properties include wells and properties primarily located in the Joaquin, Carthage, Willow Springs, and East Henderson fields in East Texas. Those properties collectively contained 431.7 Bcfe of estimated net proved reserves as of December 31, 2016 based on our reserve report and generated average net production of 128.7 MMcfe/d for the three months ended December 31, 2016.

Rockies

Approximately 24% of our estimated proved reserves as of December 31, 2016 and approximately 14% of our average daily net production for the three months ended December 31, 2016 were located in the Rockies region. Our Rockies properties include wells and properties primarily located in the Lost Soldier and Wertz fields in Wyoming at our Bairoil complex. Our Rockies properties contained 36.8 MMBbls of estimated net proved oil and NGLs reserves as of December 31, 2016 based on our reserve report and generated average net production of 28.3 MMcfe/d for the three months ended December 31, 2016.

13


Offshore Southern California

Approximately 19% of our estimated proved reserves as of December 31, 2016 and approximately 12% of our average daily net production for the three months ended December 31, 2016 were located offshore Southern California. These properties, the Beta properties, consist of: 100% of the working interests and currently a 87.6% 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 29.3 MMBbls of estimated net proved oil reserves as of December 31, 2016 based on our reserve report. Due to low oil and gas prices, the Beta leases were all granted royalty relief by the U.S. Department of Interior in July 2016. On our two primary producing leases, the royalty rate was reduced from 25% to 12.5%, and on our third lease, the royalty rate was reduced from 16.67% to 8.33%, for a weighted average of 12.4% overall. The royalty relief rates will apply to all hydrocarbon production up to 165,801 BOE per month. Monthly production above that level and up to 331,602 BOE per month will bear royalties at 1.5 times the original effective royalty rate. For monthly production above 331,602 BOE per month, the royalty rate will return to the original effective royalty rates. The royalty relief rates will also be suspended in months in which the weighted average NYMEX oil and Henry Hub gas price exceeds $55.16 per BOE which represents a 25% premium to the average realized price recognized by the Partnership during the qualification period. The royalty relief would end in the event that the Partnership generates no benefit from the royalty relief rates due to either higher production or realized pricing for 12 consecutive months.

The Beta properties also include two wellbore production platforms, referred to as the Ellen and Eureka platforms, equipped with permanent drilling rigs and associated 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.

Based on our reserve report, the Beta field contains more than 15% of our total estimated reserves. The following table summarizes production volumes from this field from the date of acquisition through December 31, 2016:

 

 

 

Year Ended December 31,

 

 

 

2016

 

 

2015

 

 

2014

 

Production Volumes:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

 

1,445

 

 

 

860

 

 

 

637

 

Total (MMcfe)

 

 

8,672

 

 

 

5,159

 

 

 

3,822

 

Average net production (MMcfe/d)

 

 

23.7

 

 

 

14.1

 

 

 

10.5

 

The increase in the production volumes between the current and preceding fiscal year is primarily due to the acquisition of the remaining interests in our Beta properties from a third party.

South Texas

Approximately 10% of our estimated proved reserves as of December 31, 2016 and approximately 11% of our average daily net production for the three months ended December 31, 2016 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 88.3 Bcfe of estimated net proved reserves as of December 31, 2016 based on our reserve report. Those properties collectively generated average net production of 24.2 MMcfe/d for the three months ended December 31, 2016.

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. The Partnership maintains internal evaluations of our reserves in a secure reserve engineering database. Ryder Scott interacts with the Partnership’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, subject to the Chapter 11 proceedings, 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.

14


Qualifications of Responsible Technical Persons

Internal Engineers. Christa Yin is the technical person at the Partnership 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 the Partnership 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 or any of our 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 or any of our 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 25 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.

15


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, 2016, 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.

 

 

 

Reserves

 

 

 

Oil

 

 

Natural Gas

 

 

NGLs

 

 

Total

 

 

 

(MBbls)

 

 

(MMcf)

 

 

(MBbls)

 

 

(MMcfe) (1)

 

Estimated Proved Reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed

 

 

45,536

 

 

 

280,035

 

 

 

18,923

 

 

 

666,786

 

Undeveloped

 

 

20,205

 

 

 

90,981

 

 

 

6,261

 

 

 

249,779

 

Total

 

 

65,741

 

 

 

371,016

 

 

 

25,184

 

 

 

916,565

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves as a percentage of total proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

73

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Standardized measure (in thousands) (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

$

395,841

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and Natural Gas Prices (3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil – WTI per bbl

 

 

 

 

 

 

 

 

 

 

 

 

 

$

42.75

 

Natural gas – Henry Hub per MMBtu

 

 

 

 

 

 

 

 

 

 

 

 

 

$

2.48

 

 

 

(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. Risk Factors — Risks Related to Our Business — Our estimated proved reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.”

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure amounts shown above should not be construed as the current market value of our estimated oil and natural gas reserves. The 10% discount factor used to calculate standardized measure, which is required by the SEC and FASB, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Development of Proved Undeveloped Reserves

As of December 31, 2016, we had 249.8 Bcfe of proved undeveloped reserves comprised of 20.2 MMBbls of oil, 91.0 Bcfe of natural gas and 6.3 MMBbls of NGLs. None of our PUDs as of December 31, 2016 are scheduled to be developed on a date more than five years from the date the reserves were initially booked as PUDs. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

Changes in PUDs that occurred during 2016 were due to:

 

Downward performance and price revisions of 180 Bcfe;

 

Reclassifications of 41 Bcfe into proved developed reserves for implementation of drilling projects;

 

Reserve additions of 2 Bcfe; and

 

Divestitures of 1 Bcfe.

16


Approximately 9% (41 Bcfe) of our PUDs recorded as of December 31, 2015 were developed during the twelve months ended December 31, 2016. Total costs incurred to develop these PUDs were approximately $50.2 million, of which $26.5 million was incurred in fiscal year 2015 and $23.7 million was incurred in fiscal year 2016. In total, we incurred total capital expenditures of approximately $24.5 million during fiscal year 2016 developing PUDs, which includes $0.8 million associated with PUDs to be completed in 2017. As we continue to develop our properties and have more well production and completion data, we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in the upcoming years. Based on our current expectations of our cash flows, we believe that we can fund the drilling of our current PUD inventory and our expansions in the next five years from our cash flow from operations and borrowings under our expected Exit Credit Facility upon approval of our plan of reorganization in the Chapter 11 proceedings. For a more detailed discussion of our liquidity position, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

Reserves Sensitivity

Historically, commodity prices have been extremely volatile and we expect this volatility to continue for the foreseeable future. For example, for the five years ended December 31, 2016, the NYMEX-WTI oil future price ranged from a high of $110.53 per Bbl to a low of $26.21 per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $6.15 per MMBtu to a low of $1.64 per MMBtu. For the year ended December 31, 2016, the West Texas Intermediate posted price ranged from a high of $54.06 per Bbl on December 28, 2016 to a low of $26.21 per Bbl on February 11, 2016 and the Henry Hub spot market price ranged from a high of $3.93 per MMBtu on December 28, 2016 to a low of $1.64 per MMBtu on March 3, 2016. NGL prices have also suffered significant recent declines. The continuation of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

While it is difficult to quantify the impact of the continuation of low commodity prices on our estimated proved reserves with any degree of certainty because of the various components and assumptions used in the process of estimating reserves, the following sensitivity table is provided to illustrate the estimated impact of pricing changes on our estimated proved reserve volumes and standardized measure. In addition to different price assumptions, the sensitivity cases below include assumed capital and operating expense changes we would expect to realize under each scenario. Reductions in proved reserve volumes are attributable to reaching the economic limit sooner. The proved undeveloped reduction in volumes is a result of well locations no longer meeting our investment criteria as well as reaching the economic limit sooner. Sensitivity cases are used to demonstrate the impact that a change in price and cost environment may have on reserves volumes and standardized measure. There is no assurance that these prices or cost savings will actually be achieved.

 

 

 

Base Case (1)

 

 

Case A (2)

 

 

Case B (3)

 

Crude oil price ($/Bbl)

 

$

42.75

 

 

$

38.48

 

 

$

55.62

 

Natural gas price ($/MMBtu)

 

$

2.48

 

 

$

2.23

 

 

$

2.86

 

NGL price ($/Bbl)

 

$

42.75

 

 

$

38.48

 

 

$

55.62

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves (MMcfe)

 

 

666,786

 

 

 

595,142

 

 

 

827,307

 

Proved undeveloped reserves (MMcfe)

 

 

249,779

 

 

 

145,376

 

 

 

322,627

 

Total proved reserves (MMcfe)

 

 

916,565

 

 

 

740,518

 

 

 

1,149,934

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Standardized measure (in thousands)

 

$

395,841

 

 

$

222,810

 

 

$

935,252

 

 

 

(1)

SEC pricing as of December 31, 2016 before adjustment for market differentials.

 

(2)

Prices represent a 10% reduction to the SEC pricing as of December 31, 2016 based on different pricing assumptions before adjustments for market differentials.

 

(3)

Prices represent weighted-average NYMEX forward strip prices as of January 31, 2017 before adjustments for market differentials. NYMEX forward strip prices were input into our cash flow analysis as individual monthly figures through 2019, as annual average for 2020, and held constant thereafter.

Production, Revenue and Price History

For a description of our and the previous owners’ combined historical production, revenues and average sales prices and per unit costs, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.”

17


The following tables summarize our average net production, average unhedged sales prices by product and average production costs by geographic region for the years ended December 31, 2016, 2015 and 2014, respectively:

 

 

 

Year Ended December 31, 2016

 

 

 

Oil

 

 

NGLs

 

 

Natural Gas

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

Lease

 

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Operating

 

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Expense

 

 

 

(MBbls)

 

 

($/bbl)

 

 

(MBbls)

 

 

($/bbl)

 

 

(MMcf)

 

 

($/Mcf)

 

 

(MMcfe)

 

 

($/Mcfe)

 

 

($/Mcfe)

 

East Texas/Louisiana

 

 

443

 

 

$

39.48

 

 

 

1,841

 

 

$

13.64

 

 

 

37,236

 

 

$

2.45

 

 

 

50,938

 

 

$

2.62

 

 

$

0.53

 

Rockies

 

 

1,399

 

 

 

37.94

 

 

 

202

 

 

 

22.02

 

 

 

1,612

 

 

 

1.73

 

 

 

11,217

 

 

 

5.38

 

 

 

4.45

 

South Texas

 

 

416

 

 

 

39.24

 

 

 

240

 

 

 

14.95

 

 

 

5,804

 

 

 

2.29

 

 

 

9,742

 

 

 

3.41

 

 

 

1.31

 

California

 

 

1,445

 

 

 

34.97

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

8,672

 

 

 

5.83

 

 

 

3.62

 

Permian

 

 

180

 

 

 

33.39

 

 

 

 

 

 

 

 

 

124

 

 

 

2.54

 

 

 

1,204

 

 

 

5.25

 

 

 

4.10

 

Total

 

 

3,883

 

 

$

36.94

 

 

 

2,283

 

 

$

14.52

 

 

 

44,776

 

 

$

2.40

 

 

 

81,773

 

 

$

3.47

 

 

$

1.54

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average net production (MMcfe/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

223.4

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2015

 

 

 

Oil

 

 

NGLs

 

 

Natural Gas

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

Lease

 

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Operating

 

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Expense

 

 

 

(MBbls)

 

 

($/bbl)

 

 

(MBbls)

 

 

($/bbl)

 

 

(MMcf)

 

 

($/Mcf)

 

 

(MMcfe)

 

 

($/Mcfe)

 

 

($/Mcfe)

 

East Texas/Louisiana

 

 

538

 

 

$

43.93

 

 

 

2,192

 

 

$

13.79

 

 

 

40,313

 

 

$

2.68

 

 

 

56,694

 

 

$

2.86

 

 

$

0.78

 

Rockies

 

 

1,657

 

 

 

43.44

 

 

 

366

 

 

 

24.01

 

 

 

3,486

 

 

 

2.48

 

 

 

15,622

 

 

 

5.72

 

 

 

3.54

 

South Texas

 

 

460

 

 

 

45.00

 

 

 

262

 

 

 

15.59

 

 

 

6,596

 

 

 

2.54

 

 

 

10,929

 

 

 

3.80

 

 

 

1.59

 

California

 

 

860

 

 

 

41.21

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

5,159

 

 

 

6.87

 

 

 

4.45

 

Permian

 

 

572

 

 

 

45.37

 

 

 

 

 

 

 

 

 

480

 

 

 

2.51

 

 

 

3,911

 

 

 

6.94

 

 

 

7.29

 

Total

 

 

4,087

 

 

$

43.48

 

 

 

2,820

 

 

$

15.28

 

 

 

50,875

 

 

$

2.65

 

 

 

92,315

 

 

$

3.85

 

 

$

1.82

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average net production (MMcfe/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

252.9

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2014

 

 

 

Oil

 

 

NGLs

 

 

Natural Gas

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

Lease

 

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Operating

 

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Expense

 

 

 

(MBbls)

 

 

($/bbl)

 

 

(MBbls)

 

 

($/bbl)

 

 

(MMcf)

 

 

($/Mcf)

 

 

(MMcfe)

 

 

($/Mcfe)

 

 

($/Mcfe)

 

East Texas/Louisiana

 

 

540

 

 

$

89.19

 

 

 

2,096

 

 

$

30.30

 

 

 

37,422

 

 

$

4.42

 

 

 

53,238

 

 

$

5.21

 

 

$

0.83

 

Rockies

 

 

875

 

 

 

79.92

 

 

 

225

 

 

 

55.62

 

 

 

3,508

 

 

 

4.35

 

 

 

10,109

 

 

 

9.67

 

 

 

3.16

 

South Texas

 

 

419

 

 

 

87.67

 

 

 

177

 

 

 

29.86

 

 

 

7,262

 

 

 

4.13

 

 

 

10,841

 

 

 

6.65

 

 

 

2.78

 

California

 

 

637

 

 

 

85.98

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

3,820

 

 

 

14.33

 

 

 

5.76

 

Permian

 

 

664

 

 

 

85.53

 

 

 

 

 

 

 

 

 

529

 

 

 

5.89

 

 

 

4,512

 

 

 

13.27

 

 

 

6.44

 

Total

 

 

3,135

 

 

$

84.97

 

 

 

2,498

 

 

$

32.55

 

 

 

48,721

 

 

$

4.39

 

 

 

82,520

 

 

$

6.81

 

 

$

1.74

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average net production (MMcfe/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

226.0

 

 

 

 

 

 

 

 

 

18


Productive Wells

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells. The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2016.

 

 

 

Oil

 

 

Natural Gas

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Operated

 

 

191

 

 

 

185

 

 

 

1,451

 

 

 

1,210

 

Non-operated

 

 

228

 

 

 

19

 

 

 

627

 

 

 

74

 

Total

 

 

419

 

 

 

204

 

 

 

2,078

 

 

 

1,284

 

Developed Acreage

Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. As of December 31, 2016, substantially all of our leasehold acreage was held by production. The following table sets forth information as of December 31, 2016 relating to our leasehold acreage.

 

Region

 

Developed Acreage (1)

 

 

 

Gross (2)

 

 

Net (3)

 

East Texas/Louisiana

 

 

223,201

 

 

 

130,617

 

Rockies

 

 

6,693

 

 

 

6,693

 

South Texas

 

 

109,185

 

 

 

94,660

 

California

 

 

17,280

 

 

 

17,280

 

Total

 

 

356,359

 

 

 

249,250

 

 

 

(1)

Developed acres are acres spaced or assigned to productive wells or wells capable of production.

 

(2)

A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.

 

(3)

A net acre is deemed to exist when the sum of our fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Undeveloped Acreage

The following table sets forth information as of December 31, 2016 relating to our undeveloped leasehold acreage (including the remaining terms of leases and concessions).

 

 

 

Undeveloped

 

 

Net Acreage Subject to

 

Region

 

Acreage

 

 

Lease Expiration by Year

 

 

 

Gross (1)

 

 

Net (2)

 

 

2017

 

 

2018

 

East Texas/Louisiana

 

 

31,309

 

 

 

17,363

 

 

 

1,483

 

 

 

544

 

Rockies

 

 

120

 

 

 

120

 

 

 

 

 

 

120

 

South Texas

 

 

6,346

 

 

 

6,346

 

 

 

 

 

 

4,415

 

Total

 

 

37,775

 

 

 

23,829

 

 

 

1,483

 

 

 

5,079

 

 

 

(1)

A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.

 

(2)

A net acre is deemed to exist when the sum of our fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

19


Drilling Activities

Our drilling activities primarily consist of development wells. The following table sets forth information with respect to wells drilled and completed by us or the previous owners during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value. At December 31, 2016, 8 gross (0.5 net) wells were in various stages of completion.

 

 

 

Year Ended December 31,

 

 

 

2016

 

 

2015

 

 

2014

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Development wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

23.0

 

 

 

8.0

 

 

 

43.0

 

 

 

20.0

 

 

 

106.0

 

 

 

60.8

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

7.0

 

 

 

1.9

 

Exploratory wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dry

 

 

 

 

 

 

 

 

1.0

 

 

 

1.0

 

 

 

 

 

 

 

Total wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

23.0

 

 

 

8.0

 

 

 

43.0

 

 

 

20.0

 

 

 

106.0

 

 

 

60.8

 

Dry

 

 

 

 

 

 

 

 

1.0

 

 

 

1.0

 

 

 

7.0

 

 

 

1.9

 

Total

 

 

23.0

 

 

 

8.0

 

 

 

44.0

 

 

 

21.0

 

 

 

113.0

 

 

 

62.7

 

Delivery Commitments

We have no commitments to deliver a fixed and determinable quantity of our oil or natural gas production in the near future under our existing sales contracts.

We have entered into a long-term gas gathering agreement associated with a certain portion of our East Texas production with a third party midstream service provider that has volumetric requirements. Information regarding our delivery commitments under this contract is contained in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations” and Note 14 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data,” both contained herein.

Operations

General

As of December 31, 2016, the Partnership is the operator of record of properties containing 94% of our total estimated proved reserves. We design and manage the development, recompletion and/or workover operations, and supervise other operation and maintenance activities, for all of the wells we operate. We do not own the drilling rigs or other oil field services equipment used for drilling or maintaining wells on our onshore properties; independent contractors provide all the equipment and personnel associated with these activities. Our Beta platforms have permanent drilling systems in place.

Marketing and Major Customers

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

 

 

For the Year Ending December 31,

 

 

2016

 

 

2015

 

 

2014

 

Major customers:

 

 

 

 

 

 

 

 

 

 

 

Phillips 66

 

19%

 

 

 

12%

 

 

 

12%

 

Sinclair Oil & Gas Company

 

16%

 

 

 

18%

 

 

 

11%

 

Royal Dutch Shell plc and subsidiaries

 

14%

 

 

 

14%

 

 

n/a

 

The production sales agreements covering our properties contain customary terms and conditions for the oil and natural gas industry and provide for sales based on prevailing market prices. A majority of those agreements have terms that renew on a month-to-month basis until either party gives advance written notice of termination.

If we were to lose any one of our customers, the loss could temporarily delay production and sale of a portion of our oil and natural gas in the related producing region. If we were to lose any single customer, we believe we could identify a substitute customer to purchase the impacted production volumes. However, if one or more of our larger customers ceased purchasing oil or natural gas altogether and we were unable to replace them, the loss of any such customer could have a detrimental effect on our production volumes in general.

20


Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, often cursory investigation of record title is made at the time of lease acquisition. More thorough title investigations are customarily made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include customary royalty interests, liens incident to operating agreements and for current taxes, obligations or duties under applicable laws, development obligations under natural gas leases, or net profits interests.

Derivative Activities

We enter into commodity derivative contracts with unaffiliated third parties, generally lenders under our revolving credit facility or their affiliates, to achieve more predictable cash flows and to reduce our exposure to fluctuations in oil and natural gas prices. Our outstanding commodity derivative contracts currently consist of floating-for-fixed swaps. Upon filing voluntary petitions under Chapter 11 in the Bankruptcy Court, under our hedging order we limited our commodity derivative contracts with certain parties to hedge up to at least 50% of our estimated production from proved developed producing reserves over a two-to-three year period at any given point of time to satisfy the hedging covenants in our Exit Credit Facility.

Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates (such as those in our revolving credit facility) 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.

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 facility are counterparties to our derivative contracts. We will continue to evaluate the benefit of employing derivatives in the future. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional information.

Competition

We operate in a highly competitive environment for acquiring properties, leasing acreage, contracting for drilling equipment and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry and many of our competitors have access to capital at a lower cost than that available to us.

Seasonal Nature of Business

The price we receive for our natural gas production is impacted by seasonal fluctuations in demand for natural gas. The demand for natural gas typically peaks during the coldest months and tapers off during the warmest months, with a slight increase during the summer to meet the demands of electric generators. The weather during any particular season can affect this cyclical demand for natural gas. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

Hydraulic Fracturing

We use hydraulic fracturing as a means to maximize the productivity of almost every well that we drill and complete, except in our offshore wells. Hydraulic fracturing is a necessary part of the completion process because our properties are dependent upon our ability to effectively fracture the producing formations in order to produce at economic rates. Nearly all of our onshore proved non-producing and proved undeveloped reserves associated with future drilling, recompletion, and refracture stimulation projects, or approximately 22% of our total estimated proved reserves as of December 31, 2016, require hydraulic fracturing.

We have and continue to follow applicable industry standard practices and legal and regulatory requirements for groundwater protection in our operations which are subject to supervision by state and federal regulators (including the Bureau of Land Management on federal acreage). These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by regulatory agencies, and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. This aspect of well design essentially eliminates a pathway for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval.

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Injection rates and pressures are monitored instantaneously and in real time at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string. Hydraulic fracturing operations would be shut down immediately if an abrupt change occurred to the injection pressure or annular pressure.

Certain state regulations require disclosure of the components in the solutions used in hydraulic fracturing operations. Approximately 99% of the hydraulic fracturing fluids we use are made up of water and sand. The remainder of the constituents in the fracturing fluid are managed and used in accordance with applicable requirements.

Hydraulic fracture stimulation requires the use of a significant volume of water. Upon flowback of the water, we dispose of it in a way that minimizes the impact to nearby surface water by disposing into approved disposal or injection wells. We currently do not discharge water to the surface.

For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, please read “—Regulation of Environmental and Occupational Health and Safety Matters—Hydraulic Fracturing.”

Insurance

In accordance with customary industry practice, we maintain insurance against many potential operational risks and losses that could be covered by the following policies:

 

     Commercial General Liability;

     Oil Pollution Act Liability;

     Primary Umbrella / Excess Liability;

     Pollution Legal Liability;

     Property;

     Charterer’s Legal Liability;

     Workers’ Compensation;

     Non-Owned Aircraft Liability;

     Employer’s Liability;

     Automobile Liability;

     Maritime Employer’s Liability;

     Directors & Officers Liability;

     U.S. Longshore and Harbor Workers’;

     Employment Practices Liability;

     Energy Package/Control of Well;

     Crime; and

     Loss of Production Income (offshore only);

     Fiduciary

Onshore and Offshore Insurance Program. We maintain insurance coverage against potential losses that we believe is customary in the industry. As of December 31, 2016, we maintain commercial general liability insurance, automobile liability insurance and umbrella/excess liability insurance. Our commercial general liability insurance has limits of $1.0 million per occurrence/$2.0 million in the aggregate and a $250,000 self-insured retention. Our general liability insurance covers us for, among other things, legal and contractual liabilities arising out of third party property damage and bodily injury and for sudden and accidental pollution liability. Our automobile liability insurance has limits of $1.0 million per occurrence. Our umbrella/excess liability limits for each occurrence is a minimum of $25.0 million. There is no deductible on our umbrella/excess liability insurance. Our umbrella/excess liability insurance is in addition to our general and automobile liability policy and may be triggered if the general or automobile liability insurance policy limits are exceeded and exhausted. In addition, we maintain an energy package policy that includes control of well coverage (“COW”) with per occurrence limits for COW ranging from $10.0 million to $100.0 million and retentions ranging from $100,000 to $500,000, with an additional annual aggregate retention of $1.0 million.  Specific to offshore operations, the energy package policy also includes loss of production income coverage insuring us against a loss up to $52.65 million due to a temporary interruption in the oil supply from our offshore facilities as a result of an insured physical loss to our offshore facilities. Our control of well policy insures us for blowout risks associated with drilling, completing and operating our wells. We maintain two separate Pollution Legal Liability (“PLL”) policies, one for all U.S. onshore operations, excluding California and one for California only. Our PLL non-California insurance policy has limits of $10.0 million per pollution event with a $1.0 million retention.  Our PLL California-only insurance policy has limits of $10.0 million with a $250,000 retention.

As of December 31, 2016, we have insurance policies in effect that are intended to provide coverage for pollution losses including those related to our hydraulic fracturing operations. These policies may not cover fines, penalties or costs and expenses related to government-mandated clean-up of pollution. In addition, these policies do not provide coverage for all liabilities. Our insurance coverage may not be adequate to cover claims that may arise, and we may be unable to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

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We enter into master services agreements, or MSAs, with various service providers. These MSAs allocate potential liabilities and risks between the parties. Under certain MSAs, we indemnify certain service providers, including hydraulic fracturing service providers, for pollution and contamination of any kind, damages to or losses from wells or underground formations and damages to property, including pipelines, storage or production facilities. Under certain other MSAs, the service providers indemnify us for pollution or contamination that originates above the surface and is caused by the service provider’s equipment or services, unless such pollution or contamination is caused by our gross negligence or willful misconduct, and we indemnify the service providers for all other pollution or contamination that may occur during operations (including that which may result from seepage or any other uncontrolled flow of oil, natural gas or other fluids from the well), unless such pollution or contamination is caused by the service provider’s gross negligence or willful misconduct. Generally, we also agree to indemnify the service providers against claims arising from our employees’ bodily injury or death to the extent that our employees are injured by or during service operations, unless resulting from the service provider’s gross negligence or willful misconduct. Similarly, the service providers generally agree to indemnify us for liabilities arising from bodily injury to or death of any of their employees, unless resulting from our gross negligence or willful misconduct. In addition, the service providers generally agree to indemnify us for loss or destruction of property or equipment that they own, unless resulting from our gross negligence or willful misconduct. In turn, we generally agree to indemnify the service providers for loss or destruction of property or equipment we own, unless resulting from the service provider’s gross negligence or willful misconduct.

Despite the general allocation of risk discussed above, we may not succeed in enforcing such contractual allocation of risk, we may be required to enter into a MSA with terms that vary from such allocation of risk and may incur costs or liabilities that fall outside any contractual allocation of risk. As a result, we may incur substantial losses that could materially and adversely affect our financial position, results of operations and cash flows.

Environmental, Occupational Health and Safety Matters and Regulations

General

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, 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 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 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.

The following is a summary of the more significant existing environmental, occupational health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

BOEM & BSEE

Our oil and gas operations associated with our Beta properties are conducted on offshore leases in federal waters. The Bureau of Ocean Energy Management, or BOEM, and the Bureau of Safety and Environmental Enforcement, or BSEE have broad authority to regulate our oil and gas operations associated with our Beta properties.

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BOEM is responsible for managing environmentally and economically responsible development of the nation’s offshore resources. Its functions include offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act analysis and environmental studies. 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, the EPA, U.S. Department of Transportation, and the South Coast Air Quality Management District. BOEM generally requires that lessees have substantial net worth, post supplemental bonds or provide other acceptable assurances that the obligations will be met. In July 2016, BOEM issued updated guidance for determining if and when additional security is required for Outer Continental Shelf, or OCS, leases, pipeline rights-of-way, and rights-of-use and easement. The new criteria may require lessees or operators to take additional steps to demonstrate that they have the financial ability to carry out their obligations. In January 2017, BOEM announced that the implementation timeline would be extended for six months.

BSEE is responsible for safety and environmental oversight of offshore oil and gas operations. Its functions include the development and enforcement of safety and environmental regulations, permitting offshore exploration, development and production, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs. BSEE has regulations requiring offshore production facilities and pipelines located on the OCS, 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. BSEE has regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities.

BOEM and BSEE have adopted regulations providing for enforcement actions, including civil penalties, and lease forfeiture or cancellation for failure to comply with regulatory requirements for offshore operations. If we fail to pay royalties or comply with safety and environmental regulations, 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 liability.

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. The study was completed in May 2016, finding no significant impact from these activities.  While BSEE has resumed its review of permit applications involving hydraulic fracturing operations or acid well stimulation on the Pacific OCS, the State of California and environmental groups filed lawsuits in December 2016 challenging the environmental study, which, if successful, could delay or restrict the issuance of permits involving hydraulic fracturing and/or acid well stimulation. Although we do not use either hydraulic fracturing or acid stimulation routinely, delays in the approval or refusal of plans and issuance of permits by BOEM or BSEE because of staffing, economic, environmental or other reasons (or other actions taken by 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.

Hazardous Substances and Waste Handling

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict and, in some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, referred to as CERCLA or the Superfund law, and comparable state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons deemed “responsible parties.” These persons include current owners or operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release or disposal of hazardous substances, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file common law-based claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. Also, comparable state statutes may not contain a similar exemption for petroleum. In addition, we may have liability for releases of hazardous substances at our properties by prior owners or operators or other third parties.

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The Oil Pollution Act of 1990, or OPA, is the primary federal law imposing oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Under the OPA, strict, joint and several liability may be imposed on “responsible parties” for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility. The OPA establishes a liability limit for onshore facilities, but these liability limits may not apply if: a spill is caused by a party’s gross negligence or willful misconduct; the spill resulted from violation of a federal safety, construction or operating regulation; or a party fails to report a spill or to cooperate fully in a clean-up. We are also subject to analogous state statutes that impose liabilities with respect to oil spills. For example, the California Department of Fish and Game's Office of Oil Spill Prevention and Response have adopted oil-spill prevention regulations that overlap with federal regulations.

We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act, or RCRA, as amended, and comparable state statutes. Although RCRA regulates both solid and hazardous wastes, it imposes stringent requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. These wastes, instead, are regulated under RCRA's less stringent solid waste provisions, state laws or other federal laws. It is possible that these wastes, which could include wastes currently generated during our operations, could be designated as “hazardous wastes” in the future and, therefore, be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and gas exploration and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste. It has until March 2019 to determine whether any revisions are necessary. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.

It is possible that our oil and natural gas operations may require us to manage naturally occurring radioactive materials, or NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states have enacted regulations governing the handling, treatment, storage and disposal of NORM.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with the requirements of CERCLA, RCRA, OPA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations required under such laws and regulations. Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Water Discharges and Other Waste Discharges & Spills

The Federal Water Pollution Control Act (also known as the Clean Water Act), the Safe Drinking Water Act, or the SDWA, the OPA and analogous state laws, impose restrictions and strict controls with respect to the unauthorized discharge of pollutants, including oil and hazardous substances, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. The underground injection of fluids is subject to permitting and other requirements under state laws and regulation. Obtaining permits has the potential to delay the development of natural gas and oil projects. These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development, and require us to incur compliance costs.

These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and the underground injection of fluids and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. We maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with their terms.

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Hydraulic Fracturing

We use hydraulic fracturing extensively in our onshore operations, but not our offshore operations. 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 low permeability 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. 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 SDWA involving the use of diesel fuels and published permitting guidance in February 2014 addressing the use of diesel in fracturing operations. In addition, the EPA plans to develop a Notice of Proposed Rulemaking, which would describe a proposed mechanism – regulatory, voluntary, or a combination of both – to collect data on hydraulic fracturing chemical substances and mixtures. Also, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. 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.

Further, on August 16, 2012, the EPA published final rules that subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the new source performance standards (“NSPS”) and the National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs. The rules include NSPS 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 rules could require a number of modifications to our operations including the installation of new equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and VOC emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. On the same day, the EPA finalized a plan to implement its minor new source review program in Indian country for oil and natural gas production, and it issued for public comment an information request that will require companies to provide extensive information instrumental for the development of regulations to reduce methane emissions from existing oil and gas sources.   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 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. On June 21, 2016, the United States District Court for Wyoming set aside the rule, holding that the BLM lacked Congressional authority to promulgate the rule. The BLM has appealed the decision to the Tenth Circuit Court of Appeals. Also, on November 15, 2016, the BLM finalized a rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands. The rule requires 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 also clarifies when operators owe the government royalties for flared gas. State and industry groups have challenged this rule in federal court, asserting that the BLM lacks authority to prescribe air quality regulations.

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Several states have also adopted, or are considering adopting, regulations requiring the disclosure of the chemicals used in hydraulic fracturing and/or otherwise impose additional requirements for hydraulic fracturing activities. For example, in October 2011, the Louisiana Department of Natural Resources adopted 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 (“Commission”) and the public the chemicals used in the hydraulic fracturing process, as well as the total volume of water used. Also, in May 2013, the Commission issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The “well integrity rule” took effect in January 2014. 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. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

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. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. 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 recently completed a study regarding 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.

A number of lawsuits and enforcement actions have been initiated across the country alleging that hydraulic fracturing practices have induced seismic activity and adversely impacted drinking water supplies, use of surface water, and the environment generally. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. In the event state or local 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 new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.

In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. For example, 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. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing, and any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.

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Air Emissions

The federal Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and the imposition of other requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, on August 16, 2012, the EPA published final regulations under the CAA that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail above under the caption “Hydraulic Fracturing.”

The South Coast Air Quality Management District, or SCAQMD, is a regulatory subdivision of the State of California and responsible for air pollution control within Orange County and designated portions of Los Angeles, Riverside, and San Bernardino Counties. Our Beta properties and associated facilities are subject to regulation by the SCAQMD.

We may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing air emission related issues, which may have a material adverse effect on our operations. Obtaining permits also has the potential to delay the development of oil and natural gas projects. We believe that we currently are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our current operations.

Regulation of “Greenhouse Gas” Emissions

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, in May 2010, the EPA adopted regulations under existing provisions of the federal Clean Air Act, or CAA, that, among other things, established Prevention of Significant Deterioration (“PSD”) and Title V permit requirements for certain large stationary sources that are potential major sources of GHG emissions. The so-called Tailoring Rule established new GHG emissions thresholds that determine when stationary sources must obtain permits under the PSD and Title V programs of the Clean Air Act. 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 August 26, 2016, the EPA proposed changes needed to bring the EPA’s air permitting regulations in line with the Supreme Court’s decision on greenhouse gas permitting. The proposed rule was published in the Federal Register on October 3, 2016 and the public comment period closed on December 2, 2016.

In September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. In October 2015, the EPA amended the GHG reporting rule to add the reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines. 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.

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, including final Carbon Pollution Standards for new, modified and reconstructed power plants, a final Clean Power Plan to cut carbon dioxide pollution from existing power plants, and a proposed federal plan to implement the Clean Power Plan emission guidelines. Upon publication of the Clean Power Plan on October 23, 2015, more than two dozen States as well as industry and labor groups challenged the Clean Power Plan in the D.C. Circuit Court of Appeals. On February 9, 2016, the Supreme Court stayed the implementation of the Clean Power Plan while legal challenges to the rule proceed. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

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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, 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 went into effect on November 4, 2016. The Agreement, establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. Also, on June 29, 2016, the leaders of the United States, Canada and Mexico announced an Action Plan to, among other things, boost clean energy, improve energy efficiency, and reduce greenhouse gas emissions. The Action Plan specifically calls for a reduction in methane emissions from the oil and gas sector by 40 to 45 percent by 2025.

Restrictions on GHG emissions that may be imposed could adversely affect the oil and natural gas industry. Any GHG regulation could increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; and utilize electric driven compression at facilities to obtain regulatory permits and approvals in a timely manner. While we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

In addition, claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury or property damages. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could adversely impact our business, financial condition and results of operations.

Finally, 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, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our development and production operations.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Departments of Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency prepares an environmental assessment to evaluate the potential direct, indirect and cumulative impacts of a proposed project. If impacts are considered significant, the agency will prepare a more detailed environmental impact study that is made available for public review and comment. All of our current development and production activities, as well as proposed development plans, on federal lands, including those in the Pacific Ocean, require governmental permits that are subject to the requirements of NEPA. This environmental impact assessment process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

Endangered Species Act

The federal Endangered Species Act, or ESA, and analogous state statutes restrict activities that may adversely affect endangered and threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The designation of previously unidentified endangered or threatened species in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. Numerous species have been listed or proposed for protected status in areas in which we currently, or could in the future, undertake operations. The presence of protected species in areas where we operate could impair our ability to timely complete or carry out those operations, lose leaseholds as we may not be permitted to timely commence drilling operations, cause us to incur increased costs arising from species protection measures, and, consequently, adversely affect our results of operations and financial position.

Occupational Safety and Health Act

We are also subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements.

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Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on our assets. Additionally, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and natural gas industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress, and the development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production

Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

 

the location of wells;

 

the method of drilling and casing wells;

 

the surface use and restoration of properties upon which wells are drilled;

 

the plugging and abandoning of wells; and

 

notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

Sale and Transportation of Gas and Oil

The Federal Energy Regulatory Commission, or the FERC, approves the construction of interstate gas pipelines and the rates and service conditions for the interstate transportation of gas, oil and other liquids by pipeline. Although the FERC does not regulate the production of gas, the FERC exercises regulatory authority over wholesale sales of gas in interstate commerce through the issuance of blanket marketing certificates that authorize the wholesale sale of gas at market rates and the imposition of a code of conduct on blanket marketing certificate holders that regulate certain affiliate interactions. The FERC does not regulate the sale of oil or petroleum products or the construction of oil or other liquids pipelines. The FERC also has oversight of the performance of wholesale natural gas markets, including the authority to facilitate price transparency and to prevent market manipulation. In furtherance of this authority, the FERC imposed an annual reporting requirement on all industry participants, including otherwise non-jurisdictional entities, engaged in wholesale physical natural gas sales and purchases in excess of a minimum level. The agency’s actions are intended to foster increased competition within all phases of the gas industry. To date, the FERC’s pro-competition policies have not materially affected our business or operations. It is unclear what impact, if any, future rules or increased competition within the gas industry will have on our gas sales efforts.

The FERC and other federal agencies, the U.S. Congress or state legislative bodies and regulatory agencies may consider additional proposals or proceedings that might affect the gas or oil industries. We cannot predict when or if these proposals will become effective or any effect they may have on our operations. We do not believe, however, that any of these proposals will affect us any differently than other gas producers with which we compete.

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The Beta properties include the San Pedro Bay Pipeline Company, which owns and operates an offshore crude pipeline. This pipeline is subject to regulation by the FERC under the Interstate Commerce Act, or ICA, and the Energy Policy Act of 1992. Tariff rates for liquids pipelines, which include both crude oil pipelines and refined products pipelines, must be just and reasonable and non-discriminatory. FERC regulations require that interstate oil pipeline transportation rates and terms of service be filed with the FERC and posted publicly. The FERC has established a formulaic methodology for petroleum pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. The FERC reviews the formula every five years. Effective July 1, 2016, the current index for the five-year period ending July 2021 is the producer price index for finished goods plus an adjustment factor of 1.23 percent. The San Pedro Bay Pipeline Company uses the indexing methodology to change its rates.

The Outer Continental Shelf Lands Act requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. BOEM/BSEE has established formal and informal complaint procedures for shippers that believe that have been denied open and nondiscriminatory access to transportation on the OCS.

The U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, or PHMSA, regulates all pipeline transportation in or affecting interstate or foreign commerce, including pipeline facilities on the OCS. The San Pedro Bay pipeline is subject to regulation by the PHMSA. Recently, the PHMSA has proposed additional regulations for gas pipeline safety. For example, in March 2016, the PHMSA proposed a rule that would expand integrity management requirements beyond High Consequence Areas to gas pipelines in newly defined Moderate Consequence Areas. The public comment period closed on July 7, 2016. Also, on January 10, 2017, the PHMSA approved final rules expanding its safety regulations for hazardous liquid pipelines by, among other things, expanding the required use of leak detection systems, requiring more frequent testing for corrosion and other flaws, and requiring companies to inspect pipelines in areas affected by extreme weather or natural disasters. The final rule will become effective six months after publication in the Federal Register. However, because the new administration has prohibited publication until it has had time to review the pending regulations, it is not clear when, or if, the final rules will become effective.

Anti-Market Manipulation Laws and Regulations

The FERC with respect to the purchase or sale of natural gas or the purchase or the purchase or sale of transmission or transportation services subject to FERC jurisdiction, the Federal Trade Commission with respect to petroleum and petroleum products, and the Commodity Futures Trading Commission with respect to commodity and futures markets, operating under various statutes have each adopted anti-market manipulation regulations, which prohibit, among other things, fraud and price manipulation in the respective markets. These agencies hold substantial enforcement authority, including the ability to assess substantial civil penalties, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

State Regulation

Various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, the baseline Texas severance tax on oil and gas is 4.6% of the market value of oil produced and 7.5% of the market value of gas produced and saved. A number of exemptions from or reductions of the severance tax on oil and gas production is provided by the State of Texas which effectively lowers the cost of production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amount of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Employees

The directors and officers of our general partner manage our operations and activities. As of December 31, 2016, the Partnership had 289 employees. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

Offices

Our principal executive office is located at 500 Dallas Street, Suite 1600, Houston, Texas 77002. Our main telephone number is (713) 490-8900.

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Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8–K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”) are made available free of charge on our website at www.memorialpp.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the United States Securities and Exchange Commission (“SEC”). These documents are also available on the SEC website at www.sec.gov or you may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.  Our website also includes our Code of Business Conduct and Ethics and the charter of our audit committee. The information contained on, or connected to, our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

 

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ITEM 1A.

RISK FACTORS

Our business and operations are subject to many risks. The risks described below, in addition to the risks described in “Item 1. Business” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” of this annual report, may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. You should carefully consider the following risk factors together with all of the other information included in this annual report, including the financial statements and related notes, when deciding to invest in us. You should be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this annual report could have a material adverse effect on our business, financial position, results of operations and cash flows and the trading price of our securities could decline and you could lose all or part of your investment.

Risks Related to Bankruptcy

The Partnership cautions that trading in the Partnership’s securities during the pendency of the Chapter 11 proceedings is highly speculative and poses substantial risks. Trading prices for the Partnership’s securities may bear little or no relationship to the actual recovery, if any, by holders of the Partnership’s securities in the Chapter 11 proceedings.

We are subject to risks and uncertainties associated with our Chapter 11 proceedings.

On January 16, 2017, the Debtors filed voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court.

Our operations and ability to develop and execute our business plan, our financial condition, our liquidity and our continuation as a going concern, are subject to risks and uncertainties associated with our bankruptcy. These risks include the following:

 

our ability to prosecute, confirm and consummate a plan of reorganization with respect to the Chapter 11 proceedings;

 

the high costs of bankruptcy proceedings and related fees;

 

our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post emergence;

 

our ability to maintain our relationships with or attract new suppliers, service providers, customers, employees, and other third parties;

 

our ability to maintain contracts that are critical to our operations;

 

our ability to execute our business plan in the current depressed commodity price environment;

 

our ability to attract, motivate and retain key employees;

 

the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us or make other third-party motions in the Chapter 11 proceedings;

 

the ability of third parties to seek and obtain court approval to convert the Chapter 11 proceedings to Chapter 7 proceedings; and

 

the actions and decisions of our creditors and other third parties who have interests in our Chapter 11 proceedings that may be inconsistent with our plans.

Delays in our Chapter 11 proceedings increase the risks of our being unable to reorganize our business and emerge from bankruptcy and increase our costs associated with the bankruptcy process.

These risks and uncertainties could affect our business and operations in various ways. For example, negative events associated with our Chapter 11 proceedings could adversely affect our relationships with our suppliers, service providers, customers, employees, and other third parties, which in turn could adversely affect our operations and financial condition. Also, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events, take advantage of certain opportunities or pursue our business strategies. Because of the risks and uncertainties associated with our Chapter 11 proceedings, we cannot accurately predict or quantify the ultimate impact that events that occur during our Chapter 11 proceedings will have on our business, financial condition and results of operations.

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Our businesses could suffer from a long and protracted restructuring.

Our future results are dependent upon the successful confirmation and implementation of a Chapter 11 plan or other alternative restructuring transaction, including a sale of all or substantially all of the Partnership’s assets. A long period of operations under Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. Failure to obtain confirmation of a Chapter 11 plan or approval and consummation of an alternative restructuring transaction in a timely manner may harm our ability to obtain financing to fund our operations, and there is a significant risk that the value of the Partnership would be substantially eroded to the detriment of all stakeholders. If a Chapter 11 plan that complies with the applicable provisions of the Bankruptcy Code cannot be agreed upon, it is possible that we would have to liquidate our assets, in which case it is likely that holders of claims would receive substantially less favorable treatment than they would receive if we were to emerge as a viable, reorganized entity.

For as long as the Chapter 11 proceedings continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 proceedings. The Chapter 11 proceedings may also require us to seek debtor-in-possession financing to fund operations. If we are unable to obtain such financing on favorable terms or at all, our chances of successfully reorganizing our business may be seriously jeopardized, the likelihood that we instead will be required to liquidate our assets may be enhanced, and, as a result, any securities in us could become further devalued or become worthless.

There can be no assurance that we will successfully reorganize and emerge from the Chapter 11 proceedings or, if we do successfully reorganize, as to when we would emerge from the Chapter 11 proceedings.

Even after a Chapter 11 plan is confirmed and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders, suppliers and other counterparties to do business with a company that recently emerged from bankruptcy proceedings.

We have substantial liquidity needs and may be required to seek additional financing. If we are unable to obtain financing on satisfactory terms or maintain adequate liquidity, our ability to replace our proved reserves or to maintain current production levels and generate revenue will be limited.

We face uncertainty regarding the adequacy of our liquidity and capital resources and have extremely limited, if any, access to additional financing. In addition to the cash requirements necessary to fund ongoing operations, the Partnership has incurred significant professional fees and other costs in connection with preparation for the Chapter 11 proceedings and expects that it will continue to incur significant professional fees and costs throughout the Chapter 11 proceedings. We cannot assure you that cash on hand and cash flow from operations will be sufficient to continue to fund our operations and allow us to satisfy our obligations related to the Chapter 11 proceedings if and until we are able to emerge from the Chapter 11 proceedings.

Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to comply with the terms and conditions of any cash collateral order entered by the Bankruptcy Court in connection with the Chapter 11 proceedings, (ii) our ability to maintain adequate cash on hand, (iii) our ability to generate cash flow from operations, (iv) our ability to develop, confirm and consummate a Chapter 11 plan or other alternative restructuring transaction, and (v) the cost, duration and outcome of the Chapter 11 proceedings. Our ability to maintain adequate liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control. In the event that cash on hand and cash flow from operations are not sufficient to meet our liquidity needs, we may be required to seek additional financing. We can provide no assurance that additional financing would be available or, if available, offered to us on acceptable terms. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited if it is available at all. Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

Upon a showing of cause, the Bankruptcy Court may convert our Chapter 11 case to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in our Plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

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We may be subject to claims that will not be discharged in the Chapter 11 proceedings, which could have a material adverse effect on our financial condition and results of operations.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and/or (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the plan of reorganization. Any claims not ultimately discharged through a plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

Our financial results may be volatile and may not reflect historical trends.

During the Chapter 11 proceedings, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities and expenses, contract terminations and rejections, and claims assessments occur, which may significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the bankruptcy filing.

In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.

Any Partnership de-levering transaction or change in the Partnership capital structure, including in connection with a plan of reorganization in the Chapter 11 proceedings, may involve significant taxable cancellation-of-debt or other income, such that the Partnership’s unitholders may be required to pay taxes on their share of such income even if they do not receive any cash distributions from the Partnership.

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

The restructuring transactions pursuant to the Chapter 11 plan are intended to be structured in a manner that minimizes, to the extent possible, the negative tax impact of cancellation-of-debt income to the Partnership’s existing unitholders. Nevertheless, such transaction and any or other transactions the Partnership may engage in to de-lever the Partnership and manage its liquidity could result in the allocation of substantial taxable income to the Partnership’s unitholders without a corresponding cash distribution and possibly without any cash distribution. For example, the Partnership may sell assets and use the proceeds to repay existing debt, in which case unitholders would be allocated any taxable income or gain resulting from the sale. Additionally, several provisions of the Internal Revenue Code can defer or disallow any losses that may otherwise be recognized as result of a transfer of assets under certain circumstances (such as, potentially, a transfer of assets to a corporation for stock, in connection with the initial capitalization of the corporation or a transaction between related parties). Further, the Partnership may pursue other opportunities to reduce its existing debt, such as exchanges, repurchases, modifications or extinguishment of Partnership debt that could result in cancellation-of-debt income being allocated to the Partnership’s unitholders as ordinary taxable income. It is possible that the income tax liability resulting from the allocation of such cancellation-of-debt or other income, if any, to a unitholder could exceed the current value of the unitholder’s investment in the Partnership. The ultimate effect of an allocation of cancellation-of-debt income to a unitholder will depend on the unitholder’s individual tax position, including, for example, the availability of any current or prior-year “suspended” passive losses to offset all or a portion of the allocable cancellation-of-debt income.

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

Additionally, the Partnership expects to emerge from the Chapter 11 proceedings as a corporation, including for U.S. federal income tax purposes.

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Risks Related to Our Business

The terms of our indebtedness include restrictions and financial covenants that may restrict our business and financing activities.

The operating and financial restrictions and covenants in 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 such financing agreements that are not cured or waived within the appropriate time periods provided therein, 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.

The terms and conditions governing our indebtedness:

 

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;

 

increase our vulnerability to economic downturns and adverse developments in our business;

 

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;

 

place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;

 

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;

 

make it more difficult for us to satisfy our obligations under our debt and increase the risk that we may default on our debt obligations; and

 

limit management’s discretion in operating our business.

We expect our Exit Credit Facility to be at least as restrictive as our revolving credit facility. See “Item 1. Business — 2016 and 2017 Developments — Debt Instruments” for additional information regarding the Exit Credit Facility.

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

Our revolving credit facility allowed, and we expect our Exit Credit Facility will allow, us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. The 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, which could affect our cash flows and ability to execute on our business plans. Any reduction in the borrowing base would materially and adversely affect 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, the borrowing base is subject to further reduction. Our revolving credit facility required, and we expect our Exit Credit Facility will require, us to repay any deficiency over a certain period or pledge additional oil and gas properties to eliminate such deficiency, which we are required to do within 30 days of electing to do so. If our outstanding borrowings exceed the borrowing base and we are unable to repay the deficiency or pledge additional oil and gas properties to eliminate such deficiency, our failure to repay any of the installments due related to the borrowing base deficiency would constitute an event of default under the credit facility and as such, the lenders could declare all outstanding principal and interest to be due and payable, could freeze our accounts, or foreclose against the assets securing the obligations owed under the credit facility.

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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 have historically funded our operations, including our operating and capital expenditures, our debt service obligations and our acquisitions primarily through cash generated from operations, amounts available under our revolving credit facility and equity and debt offerings. Our future cash flows are subject to a number of variables, including oil and natural gas prices, and due to the steep decline in commodity prices, our ability to obtain funding in the equity or capital markets has been, and will continue to be, constrained, and there can be no assurances that our liquidity requirements will continue to be satisfied given current commodity prices.  If our sources of liquidity are not sufficient to fund our current or future liquidity needs, including as a result of a decrease in the borrowing base under our revolving credit facility, we may be required to take other actions, including those actions discussed below.

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 strategic actions or financing plans, such as:

 

refinancing or restructuring our debt;

 

selling assets;

 

reducing or delaying capital investments;

 

seeking to raise additional capital;

 

liquidating all or a portion of our hedge portfolio;

 

seeking additional partners to develop our assets;

 

reducing our planned capital program;

 

continuing to take, and potentially increasing, our cost saving measures to reduce costs, including renegotiation contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs; or

 

revising or delaying our other strategic plans.

We continually monitor the capital markets and our capital structure and may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening our balance sheet, meeting our debt service obligations and/or achieving cost efficiency.  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 cause us to incur high transaction costs, may 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.

We can provide no assurances that any alternative strategic action or financing plan undertaken will be successful in allowing us to meet our debt obligations or will result in additional liquidity. 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 flows.

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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. 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.

The board of directors of our general partner has suspended quarterly cash distributions on common units and, in connection with the transactions contemplated by the plan of reorganization in the Chapter 11 proceedings, we will convert into an entity that will not seek to pay a quarterly cash distribution or any other amount to equity holders.

Under the terms of our partnership agreement, we distribute all of our available cash to our unitholders after reserves established by our general partner. The amount of cash available for distribution is 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, and future debt service requirements. In October 2016, the board of directors of our general partner suspended distributions on common units primarily due to the current and expected commodity price environment and market conditions and their impact on our future business as well as restrictions imposed by our debt instruments, including our revolving credit facility.

In connection with the transactions contemplated by the plan of reorganization in the Chapter 11 proceedings, the Partnership will convert into a corporation or other entity with a primary business objective other than generating stable cash flows that will allow for quarterly cash distributions to equity holders.

If we were to resume quarterly cash distributions, the cash available to service our indebtedness or otherwise operate our business may be limited and we may incur additional debt to enable us to pay such quarterly distributions.

If we were to resume quarterly cash distributions, 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.

In addition, we may be unable to pay the quarterly cash distribution, if resumed, without borrowing under our revolving credit facility or otherwise. If we use borrowings to pay distributions to our equity holders 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 equity and will have a material adverse effect on our business, financial condition and results of operations.

If we do not make acquisitions on economically acceptable terms, our future growth and ability to resume the payment of distributions will be limited.

Our ability to grow and to resume the payment of 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:

 

unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with their owners;

 

unable to obtain financing for such acquisitions on economically acceptable terms; or

 

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 unable to resume the payment of distributions to our unitholders.

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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:

 

the regional, domestic and foreign supply of oil, natural gas and NGLs;

 

the level of commodity prices and expectations about future commodity prices;

 

the level of global oil and natural gas exploration and production;

 

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;

 

the cost of exploring for, developing, producing and transporting reserves;

 

the price and quantity of foreign imports;

 

political and economic conditions in oil producing countries;

 

the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

speculative trading in crude oil and natural gas derivative contracts;

 

the level of consumer product demand;

 

weather conditions and other natural disasters;

 

risks associated with operating drilling rigs;

 

technological advances affecting exploration and production operations and overall energy consumption;

 

domestic and foreign governmental regulations and taxes;

 

the continued threat of terrorism and the impact of military and other action;

 

the price and availability of competitors’ supplies of oil and natural gas and alternative fuels; and

 

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, 2016, the NYMEX-WTI oil future price ranged from a high of $110.53 per Bbl to a low of $26.21 per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $6.15 per MMBtu to a low of $1.64 per MMBtu. Recently, oil and natural gas prices have started to increase slightly. Through December 31, 2016, the West Texas Intermediate posted price from a low of $26.21 per Bbl on February 11, 2016 to a high of $54.06 per Bbl on December 28, 2016. In addition, the Henry Hub spot market price had increased from a low of $1.64 per MMBtu on March 3, 2016 to a high of $3.93 per MMBtu on December 28, 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.

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 fund our operations.

As discussed above, oil, natural gas and NGL prices have declined significantly over the past few years. 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 fund our operations.

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We recognized $183.4 million of impairments during 2016 and $616.8 million of impairments during 2015 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.

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 2017.

The failure to replace our proved oil and natural gas reserves could adversely affect our business, financial condition, results of operations, production and cash flows.

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 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 materially and adversely affect our business, financial condition and results of operations. Further, our limited liquidity has caused us to significantly limit the development of reserves, and future development will require continued liquidity.

Our acquisition and development operations will require additional capital that may not be available.

Our business is capital intensive and requires substantial expenditures to maintain currently producing wells, to make the acquisitions and/or conduct the development activities necessary to replace our reserves, to pay expenses and to satisfy our other obligations. Low oil and natural gas prices, declines in the trading prices of our debt and equity securities and concern about the global financial markets may limit our ability to obtain funding in the capital and credit markets on terms we find acceptable, and could limit our ability to obtain additional or continued funding under our revolving credit facility or obtain any funding at all.

If we reduce our capital spending in an effort to conserve cash, this would likely result in production being lower than anticipated, and could result in reduced revenues, cash flow from operations and income. 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.

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 50% of our estimated production from proved developed producing reserves over a two-to-three 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.

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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 flows 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 resume making 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 SEC and FASB, is not necessarily 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.

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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 flows.

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:

 

high costs, shortages or delivery delays of rigs, equipment, labor, electrical power or other services;

 

unusual or unexpected geological formations;

 

composition of sour natural gas, including sulfur, carbon dioxide and other diluent content;

 

unexpected operational events and conditions;

 

failure of down hole equipment and tubulars;

 

loss of wellbore mechanical integrity;

 

failure, unavailability or shortage of capacity of gathering pipeline, particularly from the Beta properties, or other transportation facilities;

 

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;

 

title problems;

 

loss of drilling fluid circulation;

 

hydrocarbon or oilfield chemical spills;

 

fires, blowouts, surface craterings and explosions;

 

surface spills or underground migration due to uncontrollable flows of oil, natural gas, formation water or well fluids;

 

delays imposed by or resulting from compliance with environmental and other governmental or regulatory requirements; and

 

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 business, financial condition, results of operations and cash flows.

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.

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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 liability, claim or other loss not fully covered by insurance could have a material adverse effect on our business, financial position, results of operations and cash flows.

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, results of operations, and cash flows and as a result, our ability to resume 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:

 

landing our wellbore in the desired drilling zone;

 

staying in the desired drilling zone while drilling horizontally through the formation;

 

running our casing the entire length of the wellbore; and

 

being able to run tools and other equipment consistently through the horizontal wellbore.

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Risks that we face while completing our wells include, but are not limited to, the following:

 

the ability to fracture stimulate the planned number of stages;

 

the ability to run tools the entire length of the wellbore during completion operations; and

 

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 flows.

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 the Partnership’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 flows.

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:

 

the validity of our assumptions about estimated proved reserves, future production, revenues, capital expenditures, operating expenses and costs;

 

an inability to successfully integrate the assets or businesses we acquire;

 

a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

 

a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

 

the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;

 

mistaken assumptions about the overall cost of equity or debt;

 

potential lack of operating experience in the geographic market where the acquired assets or business are located;

 

an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and

 

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.

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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.

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:

 

natural disasters such as earthquakes, mudslides, fires and floods;

 

oil field service costs and availability;

 

compliance with environmental and other laws and regulations;

 

remediation and other costs resulting from oil spill releases of hazardous materials and other environmental damages; and

 

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 could adversely affect our business, financial condition, results of operations and cash flows.

Our properties are located in Texas, Louisiana, offshore Southern California, 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 adversely affect our business, financial condition, results of operations and cash flows.

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, 2016. 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 resume making 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 flows could decline. 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.”

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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 cash flows.

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 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, results of operations and cash flows.

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 flows.

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We have limited control over the activities on properties we do not operate.

Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. In addition, a third-party operator could also decide to shut-in or curtail production from wells, or plug and abandon marginal wells, on properties owned by that operator during periods of lower crude oil or natural gas prices. These limitations and our dependence on the operator and third-party working interest owners for these projects could cause us to incur unexpected future costs, lower production and materially and adversely affect our financial condition and results of operations.

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 flows.

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 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. 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.

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BSEE has regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities. BOEM generally requires that lessees have substantial net worth, post supplemental bonds or provide other acceptable assurances that the obligations will be met. In July 2016, BOEM issued updated guidance for determining if and when additional security is required for Outer Continental Shelf, or OCS, leases, pipeline rights-of-way, and rights-of-use and easement. The new criteria may require lessees or operators to take additional steps to demonstrate that they have the financial ability to carry out their obligations.  If we fail to pay royalties or comply with safety and environmental regulations, 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. The study was completed in May 2016, finding no significant impact from these activities. While BSEE has resumed its review of permit applications involving hydraulic fracturing operations or acid well stimulation on the Pacific OCS, the State of California and environmental groups filed lawsuits in December 2016 challenging the environmental study, which, if successful, could delay or restrict the issuance of permits involving hydraulic fracturing and/or acid well stimulation. Delays in the approval or refusal of plans and issuance of permits by BOEM or BSEE because of staffing, economic, environmental or other reasons (or other actions taken by 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, or GHGs, present an endangerment to public health and the environment because emissions of such gases are 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 August 26, 2016, the EPA proposed changes needed to bring the EPA’s air permitting regulations in line with the Supreme Court’s decision on greenhouse gas permitting. The proposed rule was published in the Federal Register on October 3, 2016, and the public comment period closed on December 2, 2016.

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, including a Clean Power Plan for existing power plants. On February 9, 2016, the Supreme Court stayed the implementation of the Clean Power Plan while legal challenges to the rule proceed. 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.

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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, 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, which went into effect on November 4, 2016, establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. Also, on June 29, 2016, the leaders of the United States, Canada and Mexico announced an Action Plan to, among other things, boost clean energy, improve energy efficiency, and reduce greenhouse gas emissions. The Action Plan specifically calls for a reduction in methane emissions from the oil and gas sector by 40 to 45 percent by 2025.

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.

The listing of species in areas where we operate or, alternatively, entry into certain range-wide conservation planning agreements 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.

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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, 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 proposed a new version of this rule, with respect to which the comment period closed but the rule was not adopted, and another 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. The Re-Proposed Position Limit Rule provides an exemption from the position limits for swaps that constitute “bona fide hedging positions” within the definition of such term under the Re-Proposed Position Limit Rule, subject to the party claiming the exemption complying with the applicable filing, recordkeeping and reporting requirements of the Re-Proposed Position Limit Rule.

We currently qualify for the End User Exception and will utilize it if the Clearing Rule is expanded to cover swaps in which we participate; we currently qualify for the Non-Financial End User Exception and will not be required to post margin under the Margin Rule, and our existing and anticipated hedging positions constitute “bona fide hedging positions” under the Re-Proposed Position Limit Rule and we intend to do the filing, recordkeeping and reporting necessary to utilize the bona fide hedging position exemption under the Re-Proposed Position Limit Rule if and when it becomes effective, so we do not expect to be directly affected by any of 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 (including laws and regulations giving European Union financial authorities the power to write down amounts we may be owed on hedging agreements with counterparties subject to such laws and regulations and/or require that we accept equity interests in such counterparties in lieu of cash in satisfaction of such amounts), 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 Clean Water Act, or 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.

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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, or Wyoming, where we maintain operational acreage, the EPA is encouraging state programs to review and consider use of such draft guidance. In addition, the EPA plans to develop a Notice of Proposed Rulemaking by June 2018, 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 June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. 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 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. In particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and VOC emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. On the same day, the EPA finalized a plan to implement its minor new source review program in Indian country for oil and natural gas production, and it issued for public comment an information request that will require companies to provide extensive information instrumental for the development of regulations to reduce methane emissions from existing oil and gas sources. 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. On June 21, 2016, the United States District Court for Wyoming set aside the rule, holding that the BLM lacked Congressional authority to promulgate the rule. The BLM has appealed the decision to the Tenth Circuit Court of Appeals. Also, on November 15, 2016, the BLM finalized a rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands. The rule requires 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 also clarifies when operators owe the government royalties for flared gas. State and industry groups have challenged this rule in federal court, asserting that the BLM lacks authority to prescribe air quality regulations.

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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 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 further 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. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. 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 recently completed a study regarding 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.

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Our business could be adversely affected by security threats, including cyber-security threats, and related disruptions.

As a producer of natural gas and oil, we face from time to time 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.  These security threats subject 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. 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. If any 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

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.

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 unitholders, 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 unitholders (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.

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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:

 

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;

 

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;

 

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;

 

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

 

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 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. 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.

Certain changes of control would 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 would have the following effects:

 

our unitholders’ proportionate ownership interest in us will decrease;

 

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;

 

the relative voting strength of each previously outstanding unit may be diminished; and

 

the market price of our common units may decline.

Our partnership agreement restricts the 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’ 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 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:

 

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

 

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.

The liquidity of our common units could be adversely affected if we are delisted from NASDAQ.

On January 17, 2017, we received a letter from the Listing Qualifications Department of NASDAQ notifying us that as a result of the Chapter 11 proceedings, and in accordance with NASDAQ Listing Rules 5101, 5110(b) and IM-5101-1, NASDAQ determined that the Partnership’s common units would be delisted from NASDAQ. The common units had also previously fallen below the NASDAQ’s continued listing standard in NASDAQ Listing Rule 5450(a)(1) requiring listed companies to maintain an average closing price per share of not less than $1.00 over a consecutive 30 trading-day period. We have appealed NASDAQ’s determination to delist the common units, and there is no certainty that such appeal will be successful.

Upon delisting from NASDAQ, our common units would be traded over-the-counter, more commonly known as OTC. OTC transactions involve risks in addition to those associated with transactions in securities traded on a national securities exchange such as the NASDAQ. Securities traded in OTC markets generally have substantially less volume and liquidity than securities traded on a national securities exchange as a result of various factors, including the reduced number of investors that will consider investing in the securities, fewer market makers in the securities, and a reduction in securities analysts and news media coverage. As a result, holders of equity may have difficulty selling their equity and our equity price could experience additional downward pressure. Furthermore, the price of our equity could be subject to greater volatility and could be more likely to be affected by market conditions and fluctuations, changes in our operating results, market perception of us and our business, developments regarding our restructuring, and announcements by us or other parties with an interest in our business or restructuring.

We may be subject to additional compliance requirements under applicable state laws in connection with the issuance of our securities. The lack of liquidity in our securities may also make it difficult for us to issue additional securities for financing or other purposes, or to otherwise arrange for any financing we may need in the future.

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NASDAQ does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

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. If we emerge from the Chapter 11 proceedings as a corporation, we will be required to comply with all applicable corporate governance requirements.

Tax Risks to Unitholders

Any Partnership de-levering transaction or change in the Partnership capital structure, including in connection with the plan of reorganization in the Chapter 11 proceedings, may involve significant taxable cancellation-of-debt or other income, such that the Partnership’s unitholders may be required to pay taxes on their share of such income even if they do not receive any cash distributions from the Partnership.

See risk factor above in the Risk Factors Relating to Bankruptcy regarding the potential for taxable cancellation-of-debt income as a result of the restructuring transactions pursuant to the Chapter 11 proceedings. In addition, if we emerge from the Chapter 11 proceedings as a corporation (as is currently contemplated), our tax characteristics will differ significantly from those set forth in the foregoing risk factors.

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, the value of an investment in our units could be negatively impacted.

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. Any 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, such change would likely cause a substantial reduction in the value of our units.

The Partnership expects to emerge from the Chapter 11 proceedings as a corporation, including for U.S. federal income tax purposes.

If we were subjected to a material amount of additional entity-level taxation by individual states, the value of an investment in our units could be negatively impacted.

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 negatively impact the value of an investment in our units.

The Partnership expects to emerge from the Chapter 11 proceedings as a corporation, including for U.S. federal and applicable state and local income tax purposes.

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.

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On January 19, 2017, the U.S. Treasury Department and the IRS publicly released the text of final regulations regarding qualifying income under Section 7704(d)(1)(E) of the Code, which were scheduled to be formally published in the Federal Register on January 24, 2017. On January 20, 2017, the new administration released a memorandum that generally delayed all pending regulations from publication in the Federal Register pending their review and approval. On January 24, 2017, the final regulations were published in the Federal Register despite the regulatory freeze mandated by the new administration. We do not believe the final regulations affect our ability to qualify as a publicly traded partnership. However, there are no assurances that the final regulations will not be withdrawn in compliance with the temporary regulatory freeze. In addition, any changes to the final 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.

The Partnership expects to emerge from the Chapter 11 proceedings as a corporation, including for U.S. federal income tax purposes.

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.

In past years, 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. The new administration has called for a comprehensive tax reform that would significantly change U.S. tax laws. It is unclear whether any of the foregoing proposals will be considered and enacted as part of tax reform legislation, 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 value of an investment in our units could be negatively impacted.

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.

The Partnership expects to emerge from the Chapter 11 proceedings as a corporation, including for U.S. federal income tax purposes.

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.

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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.

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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, Wyoming and California. We divested our remaining property located in Colorado during June 2016. Louisiana and California 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.  As a result of any such audit adjustment, we may be required to make payments of taxes, penalties and interest.  These rules are not applicable to us for tax years beginning on or prior to December 31, 2017.

Additionally, the Partnership expects to emerge from the Chapter 11 proceedings as a corporation, including for U.S. federal income tax purposes, in which case such rules would not be applicable to us going forward.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

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.

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ITEM 3.

LEGAL PROCEEDINGS

On January 16, 2017, the Debtors filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Chapter 11 proceedings are being jointly administered for procedural purposes only by the Bankruptcy Court under the caption In re Memorial Production Partners LP, et al. (Case No. 17-30262).  As a result of the Chapter 11 proceedings, attempts to prosecute, collect, secure or enforce remedies with respect to pre-petition claims against the Debtors are subject to the automatic stay provisions of Section 362(a) of the Bankruptcy Code, including litigation relating to the entities involved in the Chapter 11 proceedings. See Note 2 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information.

In addition to the Chapter 11 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. On January 13, 2017, the Partnership received a letter from the EPA concerning potential violations of CAA section 112(r) associated with our Bairoil complex in Wyoming. The Partnership met with the EPA on February 16, 2017 to present relevant information related to the allegations. We currently cannot estimate the potential penalties, fines or other expenditures, if any, that may result from any EPA actions relating to the alleged violations and, therefore, we cannot determine if the ultimate outcome of this matter will have a material impact on the Partnership’s financial position, results of operations or cash flows. Other than the Chapter 11 proceedings and the alleged CAA violations discussed herein, based on facts currently available, 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; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

 

 

60


PART II

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 10, 2017, there were approximately 114 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:  

 

Common Unit

 

 

 

 

 

 

Price Range

 

 

Cash

 

 

High

 

 

Low

 

 

Distributions

 

2016

 

 

 

 

 

 

 

 

 

 

 

4th Quarter

$

1.78

 

 

$

0.12

 

 

n/a

 

3rd Quarter

$

2.09

 

 

$

1.34

 

 

n/a

 

2nd Quarter

$

3.07

 

 

$

1.68

 

 

$

0.0300

 

1st Quarter

$

3.21

 

 

$

1.57

 

 

$

0.0300

 

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

4th Quarter

$

7.05

 

 

$

1.57

 

 

$

0.1000

 

3rd Quarter

$

15.12

 

 

$

4.64

 

 

$

0.3000

 

2nd Quarter

$

18.10

 

 

$

14.44

 

 

$

0.5500

 

1st Quarter

$

18.71

 

 

$

13.88

 

 

$

0.5500

 

Notice of Delisting

On January 17, 2017, the Partnership received a letter from the Listing Qualifications Department of NASDAQ notifying the Partnership that (1) as a result of the Chapter 11 proceedings, and in accordance with NASDAQ Listing Rules 5101, 5110(b) and IM-5101-1, NASDAQ had determined that the Partnership’s common units would be delisted from NASDAQ and (2) accordingly, unless the Partnership requested an appeal of this determination, trading of the common units would have been suspended at the opening of business on January 26, 2017 and the Partnership’s securities would have been removed from listing and registration on NASDAQ. The Partnership has appealed this determination. See Note 2 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information.

Cash Distribution Policy

Available Cash

Our amended 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:

 

less, the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to:

 

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; or

 

comply with applicable law, any of our debt instruments or other agreements;

 

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.

In October 2016, the board of directors of our general partner suspended the distributions on common units primarily due to the current and expected commodity price environment and market conditions and their impact on our future business as well as restrictions imposed by our debt instruments, including our revolving credit facility. The board of directors of our general partner believes the suspension in distributions is in the best interest of the Partnership. Subject to the Chapter 11 proceedings, 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.

General Partner Interest

Our general partner currently owns a non-economic general partner interest in us.

61


Prior to the MEMP GP Acquisition, our general partner was entitled to 0.1% of all our distributions of available cash that we made prior to our liquidation. Our general partner’s initial 0.1% interest in these distributions would have been reduced if we had issued additional units and our general partner did not contribute a proportionate amount of capital to us to maintain its initial 0.1% general partner interest. Our general partner was not obligated to contribute a proportionate amount of capital to us to maintain its general partner interest. We had also issued incentive distribution rights (“IDRs”), which entitled the holder(s) thereof to additional increasing percentages, up to a maximum of 24.9% of the cash we distributed in excess of $0.54625 per common unit per quarter. Our general partner previously owned 50%, and the Funds indirectly owned 50%, of the IDRs. In connection with the closing of the MEMP GP Acquisition, the IDRs were canceled.  

Issuer Purchases of Equity Securities

The following table summarizes our repurchase activity during the periods indicated below:

 

 

 

 

 

 

 

 

 

 

 

 

Approximate Dollar

 

 

 

 

 

 

 

 

 

 

Total Number of

 

Value of Units

 

 

 

 

 

 

Average

 

 

Units Purchased

 

That May Yet

 

 

Total Number of

 

 

Price Paid

 

 

as Part of Publicly

 

Be Purchased

Period

 

Units Purchased

 

 

per Unit

 

 

Announced Plans

 

Under the Plans

 

 

 

 

 

 

 

 

 

 

 

 

(in thousands)

Restricted Unit Repurchases (1)

 

 

 

 

 

 

 

 

 

 

 

 

October 1, 2016 - October 31, 2016

 

 

1,313

 

 

$

1.57

 

 

n/a

 

n/a

November 1, 2016 - November 30, 2016

 

 

 

 

$

 

 

n/a

 

n/a

December 1, 2016 - December 31, 2016

 

 

 

 

$

 

 

n/a

 

n/a

 

(1)

Restricted common units are generally net-settled by unitholders to cover the required withholding tax upon vesting. See Note 12 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

62


ITEM 6.

SELECTED FINANCIAL DATA

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

Basis of Presentation. The selected financial data as of, and for the years ended, December 31, 2016, 2015, 2014, 2013 and 2012 have been derived from our consolidated financial statements and the previous owners’ combined financial statements. The combined financial statements of the previous owners reflect certain oil and gas properties acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates, the consolidated financial statements of REO from February 3, 2009 (inception) through December 11, 2012, the WHT Properties owned by WHT from February 2, 2011 (inception) through the date of acquisition, the Cinco Group from inception through October 1, 2013 and the Property Swap in February 2015 for periods after common control commenced through the date of acquisition. The combined selected financial data of the previous owners may not necessarily be indicative of the actual results of operations that might have occurred if the Partnership operated those assets separately during those periods.

Comparability of the information reflected in selected financial data. The comparability of the results of operations among the periods presented below is impacted by the following acquisitions:

 

Two separate acquisitions of assets in East Texas in May and September 2012, respectively, for a net purchase price of approximately $126.9 million;

 

The acquisition of working interests, royalty interests and net revenue interests located in the Permian Basin from a third party in July 2012 for a net purchase price of approximately $74.7 million;

 

Multiple acquisitions of operating and non-operating interests in certain oil and natural gas properties throughout 2012 primarily located in the Permian Basin for an aggregate net purchase price of $75.9 million;

 

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;

 

The acquisition of certain oil and natural gas liquids properties in Wyoming from a third party in July 2014 for a total purchase price of approximately $906.1 million;

 

The acquisition of the remaining interest in the Beta properties from a third party in November 2015 for approximately $94.6 million;

 

The sale of assets located in the Permian Basin (the “Permian Divestiture”) in June 2016 for approximately $36.7 million; and

 

The sale of assets located in Colorado and Wyoming (the “Rockies Divestiture”) in July 2016 for approximately $16.4 million.

63


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.

 

 

For Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

 

2013

 

 

2012

 

 

($ in thousands, except per unit data)

 

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil & natural gas sales

$

284,051

 

 

$

355,422

 

 

$

561,677

 

 

$

391,440

 

 

$

298,305

 

Pipeline tariff income and other

 

529

 

 

 

2,725

 

 

 

4,366

 

 

 

3,075

 

 

 

3,253

 

Total revenues

 

284,580

 

 

 

358,147

 

 

 

566,043

 

 

 

394,515

 

 

 

301,558

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

126,175

 

 

 

168,199

 

 

 

143,733

 

 

 

94,591

 

 

 

86,013

 

Gathering, processing, and transportation

 

34,979

 

 

 

34,939

 

 

 

31,892

 

 

 

25,055

 

 

 

12,466

 

Exploration

 

981

 

 

 

2,317

 

 

 

2,750

 

 

 

1,322

 

 

 

9,340

 

Taxes other than income

 

15,540

 

 

 

25,828

 

 

 

33,141

 

 

 

18,447

 

 

 

15,354

 

Depreciation, depletion, and amortization

 

171,629

 

 

 

195,814

 

 

 

185,955

 

 

 

113,814

 

 

 

101,624

 

Impairment of proved oil and natural gas properties

 

183,437

 

 

 

616,784

 

 

 

407,540

 

 

 

4,072

 

 

 

22,994

 

General and administrative

 

63,280

 

 

 

56,671

 

 

 

49,124

 

 

 

54,947

 

 

 

35,112

 

Accretion of asset retirement obligations

 

10,231

 

 

 

7,125

 

 

 

5,773

 

 

 

4,988

 

 

 

4,458

 

(Gain) loss on commodity derivative instruments

 

117,105

 

 

 

(462,890

)

 

 

(492,254

)

 

 

(26,133

)

 

 

(24,405

)

Gain (loss) on sale of properties

 

(2,754

)

 

 

(2,998

)

 

 

 

 

 

(2,848

)

 

 

(9,759

)

Other, net

 

516

 

 

 

(665

)

 

 

(11

)

 

 

647

 

 

 

38

 

Total costs and expenses

 

721,119

 

 

 

641,124

 

 

 

367,643

 

 

 

288,902

 

 

 

253,235

 

Operating income (loss)

 

(436,539

)

 

 

(282,977

)

 

 

198,400

 

 

 

105,613

 

 

 

48,323

 

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net

 

(146,031

)

 

 

(115,154

)

 

 

(83,550

)

 

 

(44,302

)

 

 

(24,955

)

Other income (expense)

 

8

 

 

 

43

 

 

 

(657

)

 

 

2

 

 

 

1

 

Gain on extinguishment on debt

 

42,337

 

 

 

422

 

 

 

 

 

 

 

 

 

 

Amortization of investment premium

 

 

 

 

 

 

 

 

 

 

 

 

 

(194

)

Total other income (expense)

 

(103,686

)

 

 

(114,689

)

 

 

(84,207

)

 

 

(44,300

)

 

 

(25,148

)

Income (loss) before income taxes

 

(540,225

)

 

 

(397,666

)

 

 

114,193

 

 

 

61,313

 

 

 

23,175

 

Income tax benefit (expense)

 

(173

)

 

 

2,175

 

 

 

1,421

 

 

 

(308

)

 

 

(108

)

Net income (loss)

 

(540,398

)

 

 

(395,491

)

 

 

115,614

 

 

 

61,005

 

 

 

23,067

 

Net income (loss) attributable to noncontrolling interest

 

 

 

 

386

 

 

 

32

 

 

 

267

 

 

 

104

 

Net income (loss) attributable to Memorial Production Partners LP

$

(540,398

)

 

$

(395,877

)

 

$

115,582

 

 

$

60,738

 

 

$

22,963

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Limited partners’ interest in net income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to Memorial Production Partners LP

$

(540,398

)

 

$

(395,877

)

 

$

115,582

 

 

$

60,738

 

 

$

22,963

 

Net (income) loss allocated to previous owners

 

 

 

 

2,268

 

 

 

2,465

 

 

 

(52,012

)

 

 

(22,842

)

Net (income) loss allocated to general partner

 

168

 

 

 

327

 

 

 

(206

)

 

 

(49

)

 

 

 

Net (income) loss allocated to NGP IDRs

 

 

 

 

(83

)

 

 

(88

)

 

 

 

 

 

 

Limited partners’ interest in net income

$

(540,230

)

 

$

(393,365

)

 

$

117,753

 

 

$

8,677

 

 

$

121

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings per unit attributable to limited partners:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic and diluted earnings per unit

$

(6.48

)

 

$

(4.71

)

 

$

1.66

 

 

$

0.19

 

 

$

0.01

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash distributions declared per unit

$

0.16

 

 

$

1.95

 

 

$

2.20

 

 

$

2.08

 

 

$

1.55

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Flow Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash flow provided by operating activities

$

408,626

 

 

$

216,751

 

 

$

254,273

 

 

$

201,703

 

 

$

183,983

 

Net cash used in investing activities

 

16,442

 

 

 

337,569

 

 

 

1,386,109

 

 

 

214,559

 

 

 

417,831

 

Net cash provided by (used in) financing activities

 

(377,410

)

 

 

120,447

 

 

 

1,111,108

 

 

 

5,969

 

 

 

237,233

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Unaudited)

 

Working capital (deficit)

$

(1,581,193

)

 

$

246,778

 

 

$

150,953

 

 

$

(3,067

)

 

$

64,797

 

Total assets

 

1,973,254

 

 

 

2,906,003

 

 

 

3,168,494

 

 

 

1,834,315

 

 

 

1,737,862

 

Current portion of long-term debt (1)

 

1,622,904

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt (1)

 

 

 

 

2,000,579

 

 

 

1,574,147

 

 

 

777,014

 

 

 

710,182

 

Total equity

 

99,489

 

 

 

645,492

 

 

 

1,296,314

 

 

 

863,021

 

 

 

864,863

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

Reduction in long-term debt is due to (i) the uncertainty regarding the Partnership’s ability to cure the default and event of default as discussed in Note 2 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data”, (ii) our inability to comply with certain financial covenants contained in our revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes.

64


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 wholly-owned by its limited partners. Our general partner, which owns a non-economic general partner interest in us, is responsible for managing all of the Partnership’s operations and activities.

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our business activities are conducted through OLLC, our wholly-owned subsidiary, and its wholly-owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, Wyoming and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs with well-known geologic characteristics and long-lived, predictable production profiles and modest capital requirements. As of December 31, 2016:

 

Our total estimated proved reserves were approximately 916.6 Bcfe, of which approximately 43% were oil and 73% were classified as proved developed reserves;

 

We produced from 2,497 gross (1,488 net) producing wells across our properties, with an average working interest of 60%, and the Partnership is the operator of record of the properties containing 94% of our total estimated proved reserves; and

 

Our average net production for the three months ended December 31, 2016 was 205.5 MMcfe/d, implying a reserve-to-production ratio of approximately 12 years.

Bankruptcy Proceedings under Chapter 11

On January 16, 2017, the Debtors filed voluntary petitions under the Bankruptcy Code in the Bankruptcy Court to pursue a Joint Chapter 11 Plan of the Reorganization for the Debtors. The Debtors’ Chapter 11 proceedings are being jointly administered under the caption In re Memorial Production Partners LP, et al. (Case No. 17-30262). The Bankruptcy Court has granted all of the first day motions filed by the Debtors, which were designed primarily to minimize the impact of the Chapter 11 proceedings on the Partnership’s operations, customers and employees. The Debtors will continue to operate their businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The Partnership expects to continue its operations without interruption during the pendency of the Chapter 11 proceedings. See Note 2 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information.

For the duration of and after the Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to risks and uncertainties associated with Chapter 11 proceedings. These risks include the risks described in Item 1A, “Risk Factors.” Because of these risks and uncertainties, the description of our operations, properties and capital plans included in this annual report may not accurately reflect our operations, properties and capital plans following the Chapter 11 proceedings.

Ability to Continue as a Going Concern

Continued low commodity prices have resulted in significantly lower levels of cash flow from operating activities and have limited the Partnership’s ability to access the capital markets. In addition, 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. Continued low commodity prices have adversely impacted our redeterminations. During the second semi-annual redetermination in October, the lenders under our revolving credit facility decreased our borrowing base to $740.0 million with a further reduction to $720.0 million in December 2016. The borrowing base was further reduced in December 2016 to $530.7 million due to the monetization of certain derivative instruments. The reduced borrowing base has had a significant negative impact on the Partnership’s liquidity and ability to remain in compliance with certain financial covenants. On January 16, 2017, the Debtors’ Chapter 11 proceedings accelerated the Partnership’s obligations under its revolving credit facility, 2021 Senior Notes and 2022 Senior Notes.

65


The significant risks and uncertainties related to the Partnership’s liquidity and Chapter 11 proceedings described above raise substantial doubt about the Partnership’s ability to continue as a going concern. The condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If the Partnership cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material.

In order to decrease the Partnership’s level of indebtedness and maintain the Partnership’s liquidity at levels sufficient to meet its commitments, the Partnership undertook a number of actions, including divesting certain non-core assets, minimizing capital expenditures and further reducing its recurring operating expenses. Despite taking these actions, the Partnership did not have sufficient liquidity to satisfy its debt service obligations, meet other financial obligations and comply with its debt covenants. As a result, the Debtors filed bankruptcy petitions under Chapter 11 of the Bankruptcy Code.

See “Item.1 Business — 2016 and 2017 Developments — Debt Instruments,” “—Liquidity and Capital Resources” below and Note 2 and 9 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our debt instruments and bankruptcy proceedings under Chapter 11.

Business Environment and Operational Focus

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) gathering, processing and transportation (vi) general and administrative expenses; and (vii) Adjusted EBITDA.

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. 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).

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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.

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:

 

High

 

 

Low

 

For the Year Ended December 31, 2016:

 

 

 

 

 

 

 

NYMEX-WTI oil future price range per Bbl

$

54.06

 

 

$

26.21

 

NYMEX-Henry Hub natural gas future price range per MMBtu

$

3.93

 

 

$

1.64

 

ICE Brent oil future price range per Bbl

$

56.82

 

 

$

27.88

 

 

 

 

 

 

 

 

 

For the Five Years Ended December 31, 2016:

 

 

 

 

 

 

 

NYMEX-WTI oil future price range per Bbl

$

110.53

 

 

$

26.21

 

NYMEX-Henry Hub natural gas future price range per MMBtu

$

6.15

 

 

$

1.64

 

ICE Brent oil future price range per Bbl

$

126.22

 

 

$

27.88

 

Commodity Derivative Contracts. 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. Quantitative and Qualitative Disclosures About Market Risk” for additional information. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering at least 50% of our estimated production from proved developed producing reserves over a two-to-three year period at any given point of time to satisfy the hedging covenants in our Exit Credit Facility. We may, however, from time to time hedge more or less than this approximate range. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. The current market conditions may also impact our ability to enter into future commodity derivative contracts.

Principal Components of Cost Structure

 

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, chemicals, 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.

 

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.

 

Exploration. These are geological and geophysical costs and include certain seismic costs, costs of unsuccessful exploratory dry holes and unsuccessful leasing efforts.

 

Taxes other than income. These consist of production, ad valorem and franchise 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.  

 

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.

 

Impairment of proved oil and natural gas properties. Proved properties are impaired whenever the net carrying value of the properties exceed their estimated undiscounted future cash flows.

 

General and administrative. 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.

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Prior to June 1, 2016, Memorial Resource provided management, administrative and operating services to the Partnership and our general partner pursuant to an omnibus agreement. Upon completion of the MEMP GP Acquisition, the omnibus agreement was terminated on June 1, 2016 and the Partnership entered into a transition services agreement with Memorial Resource to manage certain post-closing separation costs and activities. See Note 1 and Note 13 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

 

Accretion expense. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value.

 

Interest expense. Historically, we financed 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.

Outlook

Upon emergence from bankruptcy, we expect that the Partnership’s total outstanding debt balance of $1.6 billion at December 31, 2016 will be reduced by converting $1.1 billion in senior unsecured notes into 98% of the reorganized company’s equity and repayments on the revolving credit facility in 2017 prior to the January 16, 2017 bankruptcy filing. The initial borrowing base on the Exit Credit Facility is expected to be approximately $474.0 to $492.5 million based on an April emergence date and consummation of the restructuring transactions. As of January 16, 2017, we had $454.8 million in outstanding borrowings and our cash balance was $31.5 million. Upon emergence and consummation of the restructuring transactions, we expect liquidity to be at least $40.0 million depending on the size of the initial borrowing base.    

In 2017, we expect the majority of our capital expenditures to be in East Texas and California. We expect cash flows from operating activities, cash on hand and availability under the Exit Credit Facility will be adequate to meet the operating needs of the post-reorganized company, however our planned capital spending is subject to change based on the Chapter 11 proceedings and the transactions contemplated by the plan of reorganization.      

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.

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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, 2016, 2015, and 2014 have been derived from both our consolidated financial statements and our previous owners’ combined financial statements. The previous owners combined financial statements reflect 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:

 

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.

 

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 the remaining interest in the Beta properties (“2015 Beta Acquisition”) from a third party in November 2015 for approximately $94.6 million.

 

The sale of assets located in the Permian Basin (the “Permian Divestiture”) in June 2016 for approximately $36.7 million.

 

The sale of assets located in Colorado and Wyoming (the “Rockies Divestiture”) in July 2016 for approximately $16.4 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.

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The table below summarizes certain of the results of operations and period-to-period comparisons for the periods indicated.

 

For the Year Ended

 

 

December 31,

 

 

2016

 

 

2015

 

 

2014

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

Oil & natural gas sales

$

284,051

 

 

$

355,422

 

 

$

561,677

 

Other revenues

 

529

 

 

 

2,725

 

 

 

4,366

 

Total revenues

 

284,580

 

 

 

358,147

 

 

 

566,043

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

126,175

 

 

 

168,199

 

 

 

143,733

 

Gathering, processing and transportation

 

34,979

 

 

 

34,939

 

 

 

31,892

 

Exploration

 

981

 

 

 

2,317

 

 

 

2,750

 

Taxes other than income

 

15,540

 

 

 

25,828

 

 

 

33,141

 

Depreciation, depletion and amortization

 

171,629

 

 

 

195,814

 

 

 

185,955

 

Impairment of proved oil and natural gas properties

 

183,437

 

 

 

616,784

 

 

 

407,540

 

General and administrative

 

63,280

 

 

 

56,671

 

 

 

49,124

 

Accretion of asset retirement obligations

 

10,231

 

 

 

7,125

 

 

 

5,773

 

(Gain) loss on commodity derivative instruments

 

117,105

 

 

 

(462,890

)

 

 

(492,254

)

(Gain) loss on sale of properties

 

(2,754

)

 

 

(2,998

)

 

 

 

Other, net

 

516

 

 

 

(665

)

 

 

(11

)

Total costs and expenses

 

721,119

 

 

 

641,124

 

 

 

367,643

 

Operating income (loss)

 

(436,539

)

 

 

(282,977

)

 

 

198,400

 

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net

 

(146,031

)

 

 

(115,154

)

 

 

(83,550

)

Other income (expense)

 

8

 

 

 

43

 

 

 

(657

)

Gain on extinguishment of debt

 

42,337

 

 

 

422

 

 

 

 

Total other income (expense)

 

(103,686

)

 

 

(114,689

)

 

 

(84,207

)

Income (loss) before income taxes

 

(540,225

)

 

 

(397,666

)

 

 

114,193

 

Income tax benefit (expense)

 

(173

)

 

 

2,175

 

 

 

1,421

 

Net income (loss)

 

(540,398

)

 

 

(395,491

)

 

 

115,614

 

Net income (loss) attributable to noncontrolling interest

 

 

 

 

386

 

 

 

32

 

Net income (loss) attributable to Memorial Production Partners LP

$

(540,398

)

 

$

(395,877

)

 

$

115,582

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas revenue:

 

 

 

 

 

 

 

 

 

 

 

Oil sales

$

143,456

 

 

$

177,711

 

 

$

266,370

 

NGL sales

 

33,137

 

 

 

43,102

 

 

 

81,316

 

Natural gas sales

 

107,458

 

 

 

134,609

 

 

 

213,991

 

Total oil and natural gas revenue

$

284,051

 

 

$

355,422

 

 

$

561,677

 

 

 

 

 

 

 

 

 

 

 

 

 

Production volumes:

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

3,883

 

 

 

4,087

 

 

 

3,135

 

NGLs (MBbls)

 

2,283

 

 

 

2,820

 

 

 

2,498

 

Natural gas (MMcf)

 

44,776

 

 

 

50,875

 

 

 

48,721

 

Total (MMcfe)

 

81,773

 

 

 

92,315

 

 

 

82,520

 

Average net production (MMcfe/d)

 

223.4

 

 

 

252.9

 

 

 

226.0

 

 

 

 

 

 

 

 

 

 

 

 

 

Average sales price:

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

$

36.94

 

 

$

43.48

 

 

$

84.97

 

NGL (per Bbl)

 

14.52

 

 

 

15.28

 

 

 

32.55

 

Natural gas (per Mcf)

 

2.40

 

 

 

2.65

 

 

 

4.39

 

Total (Mcfe)

$

3.47

 

 

$

3.85

 

 

$

6.81

 

 

 

 

 

 

 

 

 

 

 

 

 

Average unit costs per Mcfe:

 

 

 

 

 

 

 

 

 

 

 

Lease operating expense

$

1.54

 

 

$

1.82

 

 

$

1.74

 

Gathering, processing and transportation

 

0.43

 

 

 

0.38

 

 

 

0.39

 

Taxes other than income

 

0.19

 

 

 

0.28

 

 

 

0.40

 

General and administrative expenses

 

0.77

 

 

 

0.61

 

 

 

0.60

 

Depletion, depreciation and amortization

 

2.10

 

 

 

2.12

 

 

 

2.25

 

 

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Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015

A net loss of $540.4 million was recorded for the year ended December 31, 2016, primarily due to impairment charges and loss on commodity derivatives. A net loss of $395.5 million was generated for the year ended December 31, 2015, primarily due to impairment charges partially offset by significant gains on commodity derivatives.

 

Oil, natural gas and NGL revenues for 2016 totaled $284.1 million, a decrease of $71.4 million compared with 2015. Production decreased 10.5 Bcfe (approximately 11%), primarily from decreased drilling activities, flooding in East Texas and a temporary production curtailment and planned plant turnaround at our Bairoil properties. The average realized sales price decreased $0.38 per Mcfe primarily due to lower period-to-period commodity prices. Crude oil volumes comprised 28% of total volumes for 2016 compared to 27% for 2015. The unfavorable volume and pricing variance contributed to an approximate $40.6 million decrease and $30.8 million decrease in revenues, respectively.

 

Lease operating expenses were $126.2 million and $168.2 million for 2016 and 2015, respectively. On a per Mcfe basis, lease operating expenses decreased to $1.54 for 2016 from $1.82 for 2015. Reductions in lease operating expenses were a result of our continued reductions in service provider costs and workover activities, field workforce reductions and the Permian Divestiture and Rockies Divestiture, partially offset by the 2015 Beta Acquisition.

 

Gathering, processing and transportation expenses were $35.0 million and $34.9 million for 2016 and 2015, respectively. On a per Mcfe basis, gathering, processing and transportation expenses were $0.43 for 2016 compared to $0.38 for 2015 primarily due to increased costs in East Texas.

 

Taxes other than income for 2016 totaled $15.5 million, a decrease of $10.3 million compared with 2015 primarily due to a decrease in commodity prices. On a per Mcfe basis, these taxes declined to $0.19 per Mcfe for 2016 from $0.28 per Mcfe for 2015 due to a decrease in commodity prices.

 

DD&A expense for 2016 was $171.6 million compared to $195.8 million for 2015, a $24.2 million decrease primarily due to decreased production volumes, divestitures, and impairments recognized on certain properties over the course of 2016 and 2015, partially offset by incremental DD&A as a result of the 2015 Beta Acquisition. Decreased production volumes caused DD&A expense to decrease by approximately $22.4 million and the change in the DD&A rate between periods caused DD&A expense to decrease by $1.8 million.

 

We recognized $183.4 million of impairments during 2016 related to certain properties in East Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable as a result of declining commodity prices and change in future planned development due to liquidity constraints as a result of our reduced borrowing base during the three months ended December 31, 2016. 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 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 5 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

 

General and administrative expenses for 2016 were $63.3 million, which included $10.1 million in reorganizations costs related to the restructuring process, which represents costs directly associated with the Chapter 11 proceedings for advisory and professional fees, $7.4 million of non-cash unit-based compensation expense, $2.1 million in bad debt write-off, $1.5 million of acquisition and divestiture-related costs, and $0.7 million allocated loss on previous corporate office lease. General and administrative expenses for 2015 totaled $56.7 million, which included $10.8 million of non-cash unit-based compensation expense, $1.9 million of acquisition and divestiture-related costs and a $0.8 million allocated loss on a previous corporate office lease.

 

Net losses on commodity derivative instruments of $117.1 million were recognized during 2016, consisting of $212.6 million of cash settlements received on expired positions and $230.7 million in cash settlements received on terminated derivatives. These gains were offset by a $560.4 million decrease in the fair value of open positions. 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.

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 $146.0 million during 2016, including amortization and write-offs of deferred financing fees of approximately $22.1 million and accretion and write-off of net discount associated with our senior notes of $13.2 million. Interest expense, net totaled $115.2 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. The $30.9 million increase in interest expense is primarily due to $16.9 million for the write-off of the remaining unamortized deferred financing costs, $13.2 million write-off of the remaining discount on the senior notes, and $5.4 million due to the increase in average outstanding borrowings and higher rates under our revolving credit facility during 2016 compared to 2015 partially offset by decreased period-to-period losses incurred on interest rate swaps of approximately $3.4 million during 2016 compared to 2015.

Average outstanding borrowings under the Partnership’s revolving credit facility were $746.0 million during 2016 compared to $652.2 million during 2015. For 2016, the Partnership had an average of $1.1 billion aggregate principal amount of our senior notes issued and outstanding. For 2015, the Partnership had an average of $1.2 billion aggregate principal amount of our senior notes issued and outstanding.

 

We recognized a gain on extinguishment of debt of approximately $42.3 million during 2016 related to the repurchase of the 2021 Senior Notes and 2022 Senior Notes. During 2015, we recognized a gain on extinguishment of debt of approximately $0.4 million related to the repurchase of the 2022 Senior Notes.

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.

 

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.

 

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.

 

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.

 

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.

 

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.

 

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 5 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

 

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 and divestiture-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 13 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.

 

Interest expense, net totaled $115.2 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 $31.6 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.

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;

 

Income tax expense;

 

Depreciation, depletion and amortization (“DD&A”);

 

Impairment of goodwill and long-lived assets (including oil and natural gas properties);

 

Accretion of asset retirement obligations (“AROs”);

 

Loss on commodity derivative instruments;

 

Cash settlements received on expired commodity derivative instruments;

 

Losses on sale of assets and other, net;

 

Unit-based compensation expenses;

 

Exploration costs;

 

Acquisition and divestiture related costs;

 

Amortization of gain associated with terminated commodity derivatives;

 

Reorganization costs;

 

Bad debt expense; and

 

Other non-routine items that we deem appropriate.

Less:

 

Interest income;

 

Income tax benefit;

 

Gain on extinguishment of debt

 

Gain on expired commodity derivative instruments;

 

Cash settlements paid on expired commodity derivative instruments;

 

Gains on sale of assets and other, net; and

 

Other non-routine items that we deem appropriate.

We are required to comply with certain Adjusted EBITDA-related metrics under our revolving credit facility.

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We believe presenting Adjusted EBITDA is useful because the measure 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:

 

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;

 

the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make distributions on our units; and

 

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, 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

 

For the Year Ended

 

 

December 31,

 

 

2016

 

 

2015

 

 

2014

 

Net income (loss)

$

(540,398

)

 

$

(395,491

)

 

$

115,614

 

Interest expense, net

 

146,031

 

 

 

115,154

 

 

 

83,550

 

Gain on extinguishment of debt

 

(42,337

)

 

 

(422

)

 

 

 

Income tax expense (benefit)

 

173

 

 

 

(2,175

)

 

 

(1,421

)

DD&A

 

171,629

 

 

 

195,814

 

 

 

185,955

 

Impairment of proved oil and gas properties

 

183,437

 

 

 

616,784

 

 

 

407,540

 

Accretion of AROs

 

10,231

 

 

 

7,125

 

 

 

5,773

 

(Gains) losses on commodity derivative instruments

 

117,105

 

 

 

(462,890

)

 

 

(492,254

)

Cash settlements received (paid) on expired commodity derivative instruments

 

212,566

 

 

 

254,047

 

 

 

13,522

 

Amortization of gain associated with terminated commodity derivatives

 

42,236

 

 

 

 

 

 

 

(Gain) loss on sale of properties

 

(2,754

)

 

 

(2,998

)

 

 

 

Acquisition and divestiture related expenses

 

1,451

 

 

 

1,928

 

 

 

4,363

 

Unit-based compensation expense

 

7,351

 

 

 

10,809

 

 

 

7,874

 

Exploration costs

 

981

 

 

 

2,317

 

 

 

2,750

 

Loss on office lease

 

 

 

 

 

 

 

1,442

 

Insurance recoveries related to environmental remediation

 

 

 

 

(1,216

)

 

 

 

(Gain) loss on settlement of AROs

 

531

 

 

 

1,606

 

 

 

 

Provision for environmental remediation

 

 

 

 

 

 

 

2,852

 

Reorganization costs

 

10,069

 

 

 

 

 

 

 

Bad debt expense

 

2,050

 

 

 

 

 

 

 

Other

 

229

 

 

 

 

 

 

 

Adjusted EBITDA

$

320,581

 

 

$

340,392

 

 

$

337,560

 

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Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA

 

For the Year Ended

 

 

December 31,

 

 

2016

 

 

2015

 

 

2014

 

Net cash provided by operating activities

$

408,626

 

 

$

216,751

 

 

$

254,273

 

Changes in working capital

 

(26,614

)

 

 

13,599

 

 

 

(5,669

)

Interest expense, net

 

146,031

 

 

 

115,154

 

 

 

83,550

 

Gain (loss) on interest rate swaps

 

(1,289

)

 

 

(4,674

)

 

 

151

 

Cash settlements paid (received) on interest rate derivative instruments

 

3,944

 

 

 

4,004

 

 

 

1,829

 

Cash settlements received on terminated commodity derivatives

 

(230,729

)

 

 

 

 

 

 

Amortization of gain associated with terminated commodity derivatives

 

42,236

 

 

 

 

 

 

 

Amortization and extinguishment of deferred financing fees

 

(22,106

)

 

 

(6,058

)

 

 

(4,227

)

Accretion and extinguishment of senior notes discount

 

(13,185

)

 

 

(2,430

)

 

 

(1,921

)

Acquisition and divestiture related expenses

 

1,451

 

 

 

1,928

 

 

 

4,363

 

Income tax expense (benefit) - current portion

 

(14

)

 

 

59

 

 

 

127

 

Exploration costs

 

189

 

 

 

239

 

 

 

790

 

Loss on office lease

 

 

 

 

 

 

 

1,442

 

Plugging and abandonment cost

 

1,972

 

 

 

3,036

 

 

 

 

Environmental expense

 

 

 

 

(1,216

)

 

 

 

Reorganization costs

 

10,069

 

 

 

 

 

 

 

Provision for environmental remediation

 

 

 

 

 

 

 

2,852

 

Adjusted EBITDA

$

320,581

 

 

$

340,392

 

 

$

337,560

 

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 2017, we expect our primary funding sources to be cash flows generated by operating activities, available borrowing capacity under our Exit Credit Facility and/or divestitures of assets.

If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures, and/or fund a portion of our capital expenditures using borrowings under our expected Exit 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 Exit Credit Facility. 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. See “Item.1 Business — 2016 and 2017 Developments — Debt Instruments,” for additional information regarding the terms of the Exit Credit Facility.

Revolving Credit Facility. As of December 31, 2016, we had approximately $16.6 million of available borrowing capacity under our revolving credit facility, which is net of $2.4 million in letters of credit. We had $15.4 million of cash and cash equivalents as of December 31, 2016. As of December 31, 2016, the borrowing base under our revolving credit facility was $530.7 million and we had $511.7 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.  

On January 9, 2017, we monetized certain hedge positions for approximately $94.1 million. We used approximately $73.5 million of the proceeds to repay outstanding borrowings under our revolving credit facility and kept the remaining portion as cash on hand for general partnership purposes. As a result of the hedge monetization, our borrowing base was reduced from $530.7 million to $457.2 million on January 13, 2017, at which time we had $454.8 million of outstanding borrowings. Upon the Debtors filing voluntary petitions under the Bankruptcy Code in the Bankruptcy Court, we no longer had the ability to borrow under our existing revolving credit facility. At January 16, 2017, our cash balance was $31.5 million.

See “—Ability to Continue as a Going Concern,” above for additional information regarding the Partnership’s ability to continue as a going concern.

Capital Markets. Our ability to obtain funding in the equity or capital markets has been, and will continue to be constrained. We expect to evaluate the availability of public capital as a source for future liquidity after the completion of the Chapter 11 proceedings.

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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. Quantitative and Qualitative Disclosures About Market Risk” for additional information. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering at least 50% of our estimated production from proved developed producing reserves over a two-to-three year period at any given point of time to satisfy the hedging covenants in our Exit Credit Facility. We may, however, from time to time hedge more or less than this approximate range. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. The current market conditions may also impact our ability to enter into future commodity derivative contracts.

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

Partnership Agreement. Our partnership agreement requires that we distribute all of our available cash (as defined in our partnership agreement) each quarter to our unitholders. In making cash distributions, our general partner attempts to avoid large variations in the amount we distribute from quarter to quarter. To facilitate this, our partnership agreement permits our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions to our unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to sustain our level of distributions. Our partnership agreement also permits our general partner to establish cash reserves for the proper conduct of the Partnership’s business (including reserves for future capital expenditures and for anticipated future credit needs of the Partnership) subsequent to any applicable quarter and to comply with applicable law or the Partnership’s debt instruments. Such cash reserves have the effect of reducing available cash and consequently, the distributions to our unitholders. Covenants in our revolving credit facility may also restrict our distributions. For more information related to our distributions, please read “Item 1A. Risk Factors – The board of directors of our general partner has suspended quarterly cash distributions on common units and in connection with the transactions contemplated by the plan of reorganization in the Chapter 11 proceedings we may convert into an entity that will not seek to pay a quarterly cash distribution or any other amount to equity holders.”

Capital Expenditures. In 2017, our entire capital budget will be allocated to expenditures that we expect to make on an ongoing basis to maintain our long-term asset base (including our undeveloped leasehold acreage). Our expectations for such capital expenditures may change materially in nature, timing and amount from time to time. We intend to pay for such capital expenditures from operating cash flow.

Typically, we expect to rely upon external financing sources, including credit facility borrowings and debt and common unit issuances, to fund our acquisition and growth capital expenditures. See Note 9 and Note 10 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data,” contained herein. Growth capital expenditures are capital expenditures that we expect to increase our production and the size of our asset base. The primary purpose of growth capital is to either acquire producing assets or develop internal projects on our existing asset base, like horizontal re-entry programs that increase the rate of production and provide new areas of future reserve growth.

The amount and timing of our capital expenditures is largely discretionary and within our control, with the exception of certain projects managed by other operators. If commodity prices decline below levels we deem acceptable, we may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in commodity prices, drilling and acquisition costs, industry conditions and internally generated cash flow.

Government Trust Account. In 2015, BSEE issued a preliminary report that indicated the estimated cost of decommissioning the offshore production facilities associated with the Beta properties may increase, and we expect the amount to be finalized during 2017 after negotiations are completed. At December 31, 2016, there was approximately $152.0 million in the REO trust account and $62.0 million in surety bonds.

Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable as well as the classification of our debt outstanding. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received by our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors.

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As of December 31, 2016, we had a working capital deficit of $1.6 billion primarily due to approximately $1.6 billion of our debt being recorded as a current liability at December 31, 2016. Due to (i) the uncertainty regarding the Partnership’s ability to cure the default and event of default as discussed in Note 2 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data”, (ii) our inability to comply with certain financial covenants contained in our revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes, the Partnership classified all outstanding debt balance as a current liability on its balance sheet as of December 31, 2016. As a result of the Chapter 11 filing, the debt has been accelerated. See Note 2 and Note 9 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information.

Revolving Credit Facility

OLLC is party to a $2.0 billion revolving credit facility, with a borrowing base at December 31, 2016 of $530.7 million, that matures in March 2018 and is guaranteed by us and all of our current and future subsidiaries (other than certain immaterial subsidiaries). As of December 31, 2016, we had $511.7 million of outstanding borrowings and $2.4 million of outstanding letters of credit under our revolving credit facility. 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. In the future, we may be unable to access sufficient capital under our revolving credit facility as a result of (i) a decrease in our borrowing base due to an unfavorable borrowing base redetermination or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations. Upon the Debtors filing voluntary petitions under the Bankruptcy Code in the Bankruptcy Court, we no longer had the ability to borrow under our existing revolving credit facility.

A continued decline in commodity prices could result in a redetermination that further lowers our borrowing base in the future and, in such case, we could be required to pledge additional properties as security for our revolving credit facility or repay any deficiency, which we are permitted to do in equal monthly installments over a five month period. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our revolving credit facility.

Borrowings under our revolving credit facility are currently secured by liens on substantially all of our properties, but in any event, not less than 95% 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.

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 2.25% to 3.25% 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 1.25% to 2.25% per annum according to the borrowing base usage, or (iii) the applicable LIBOR Market Index Rate plus a margin that varies from 2.25% to 3.25% per annum according to the borrowing base usage. The unused portion of the borrowing base will be subject to a commitment fee to 0.50% per annum according to the borrowing base usage.

Our revolving credit facility requires us to maintain (i) 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; (ii) 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; and (iii) a ratio of Consolidated First Lien Net Secured Debt to Consolidated EBITDAX of not greater than 3.25 to 1.0.

Additionally, our revolving credit facility contains various covenants and restrictive provisions that, among other things, limit our ability to incur or permit 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.

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Failure to pay the $24.6 million interest payment on the 2021 Senior Notes on November 1, 2016 constituted a default and event of default under our revolving credit facility, which default was subject to a waiver by the lenders under our revolving credit facility at December 31, 2016. Due to (i) the uncertainty regarding the Partnership’s ability to cure the default and event of default as discussed in Note 2 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data”, (ii) our inability to comply with certain financial covenants contained in our revolving credit facility and (iii) the default or cross default provisions in the indenture governing the 2021 Senior Notes and 2022 Senior Notes, the Partnership classified the outstanding revolving credit facility balance as a current liability on its balance sheet as of December 31, 2016. As a result of the Chapter 11 filing, the debt has been accelerated.

Senior Notes

As of December 31, 2016, there was approximately $646.3 million aggregate principal of amount of the 2021 Senior Notes outstanding. The 2021 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of our subsidiaries (other than Finance Corp., which is co-issuer of the 2021 Senior Notes, and certain immaterial subsidiaries). The 2021 Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes were issued under and are governed by a base indenture and supplements thereto. During the year ended December 31, 2016, we repurchased an aggregate principal amount of approximately $53.7 million of the 2021 Senior Notes at a weighted average price of 49.09% of the face value of the 2021 Senior Notes.

As of December 31, 2016, there was approximately $465.0 million aggregate principal amount of the 2022 Senior Notes outstanding. The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of our subsidiaries (other than Finance Corp., which is co-issuer of the 2022 Senior Notes, and certain immaterial subsidiaries). The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year. The 2022 Senior Notes were issued under and are governed by a base indenture and supplements thereto. During the year ended December 31, 2016, we repurchased an aggregate principal amount of approximately $32.0 million of the 2022 Senior Notes at a weighted average price of 46.50% of the face value of the 2022 Senior Notes.  

On November 30, 2016, the Partnership entered into (i) a Forbearance (the “2021 Notes Forbearance”) among the Partnership, Finance Corp., certain guarantors party thereto, and certain beneficial owners and/or investment advisors or managers of discretionary accounts for the holders or beneficial owners (the “2021 Holders”) of 51.7% of the aggregate principal amount of the Partnership’s 2021 Notes and (ii) a Forbearance (the “2022 Notes Forbearance” and, together with the 2021 Notes Forbearance, the “Forbearances”) among the Partnership, Finance Corp., certain guarantors party thereto, and certain beneficial owners and/or investment advisors or managers of discretionary accounts for the holders or beneficial owners (the “2022 Holders”) of 69% of the aggregate principal amount of the Partnership’s 2022 Notes.

Pursuant to each Forbearance, among other provisions, the 2021 Holders and 2022 Holders agreed that during the forbearance period, they would not enforce, or otherwise take any action to direct enforcement of, any of the rights and remedies available to the 2021 Holders, the 2022 Holders or the Trustee, as applicable, including, without limitation, any action to accelerate, or join in any request for acceleration of, the 2021 Senior Notes or the 2022 Senior Notes, solely with respect to the failure to make the interest payment due on November 1, 2016 on the 2021 Senior Notes, and the subsequent default for 30 days in such payment, which constituted an event of default under the 2021 Senior Notes indenture and may result in a cross default under the 2022 Senior Notes indenture.

On December 23, 2016, the Partnership entered into a Noteholder PSA with holders of the 2021 Senior Notes and 2022 Senior Notes. See Note 9 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information on the agreement.

The Partnership did not pay the interest due on the 2021 Senior Notes prior to the expiration of the 30-day grace period. As a result, the Partnership was in default under the terms of the indenture governing the 2021 Senior Notes and 2022 Senior Notes at December 31, 2016. The forbearance period was scheduled to expire on January 13, 2017 and the extended waiver obtained from our lenders was set to expire on January 16, 2017. Due to (i) the uncertainty regarding the Partnership’s ability to cure the default and event of default as discussed in Note 2 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data”, (ii) our inability to comply with certain financial covenants contained in our revolving credit facility and (iii) the default or cross default provisions in the indenture governing the 2021 Senior Notes and 2022 Senior Notes, the Partnership classified the outstanding senior notes balance as a current liability on its balance sheet as of December 31, 2016. As a result of the Chapter 11 filing, the debt has been accelerated.

For additional information regarding our debt instruments, see “Item 1. Business — 2016 and 2017 Developments — Debt Instruments” and Note 9 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

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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 enter into commodity derivative contracts covering approximately 50% of our estimated production from proved developed producing reserves over a two-to-three year period at any given point of time. We may, however, from time to time hedge more or less than this approximate range. It has been our practice to enter into fixed price swaps and costless collars primarily with lenders under our Credit Agreement.

During 2016, in connection with our restructuring efforts, we monetized approximately $230.7 million in commodity hedges and used the proceeds primarily to reduce amounts outstanding under our revolving credit facility and repurchase senior notes.

In January 2017, in connection with our restructuring efforts, we monetized $94.1 million in commodity hedges and used a portion of the proceeds to repay outstanding borrowings under our revolving credit facility and kept the remaining portion as cash on hand for general partnership purposes.

For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of December 31, 2016, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk.”

Interest Rate Derivative Contracts

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. During 2016, in connection with our restructuring efforts, we settled $2.1 million in interest rate swaps. For additional information, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk – Interest Rate Risk”.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for 2016, 2015, and 2014 is presented on a combined basis, consisting of the consolidated financial information of the Partnership and the combined financial information of the previous owners. For information regarding the individual components of our cash flow amounts, see the Statements of Consolidated and Combined Cash Flows included under “Item 8. Financial Statements and Supplementary Data” contained herein.

 

For the Year Ended

 

 

December 31,

 

 

2016

 

 

2015

 

 

2014

 

Net cash provided by operating activities

$

408,626

 

 

$

216,751

 

 

$

254,273

 

Net cash used in investing activities

 

16,442

 

 

 

337,569

 

 

 

1,386,109

 

Net cash (used in) provided by financing activities

 

(377,410

)

 

 

120,447

 

 

 

1,111,108

 

Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities increased by $191.9 million period-over-period. Production decreased 10.5 Bcfe (approximately 11%) and the average realized sales price decreased $0.38 per Mcfe as previously discussed under “—Results of Operations.” During 2016, oil, natural gas and NGL revenues were $284.1 million, a decrease of $71.4 million compared to 2015. Lease operating expenses were $126.2 million, a decrease of $42.0 million compared to 2015. Taxes other than income decreased to $15.5 million from $25.8 million during 2015. Cash paid for interest during 2016 was $87.5 million compared to $107.3 million during 2015. Cash settlements on terminated derivatives were $228.6 million during 2016. In 2015, we received cash settlements on terminated derivatives of $47.9 million and we paid $47.9 million in premiums for commodity derivatives. Cash settlements received on expired derivative instruments were $210.7 million during 2016 compared to $250.0 million during 2015.

Investing Activities. Net cash used in investing activities during 2016 was $16.4 million, of which $57.7 million was used for additions to oil and gas properties. This amount was partially offset by $52.7 million in proceeds from the sale of oil and natural gas properties primarily related to the Permian Divestiture and Rockies Divestiture. Cash used in investing activities during 2015 was $337.6 million, of which $100.7 million was used to acquire oil and natural gas properties from third parties and $241.3 million was used for additions to oil and gas properties. We received a post-closing settlement receipt of $9.6 million related to the July 2014 Wyoming acquisition during 2015. See Note 4 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information regarding acquisitions and divestitures.

80


Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our offshore Southern California oil and gas properties. During 2016 and 2015, additions to restricted investments were $8.4 million and $5.7 million, respectively. During 2016, we replaced $4.8 million of restricted investments with $4.8 million of surety bonds related to our decommissioning obligation of the offshore production facilities associated with the Beta properties. See Note 8 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our restricted investments.

Financing Activities. Distributions to partners during 2016 were $13.3 million compared to $163.3 million during 2015. The decrease is primarily due to a decrease in the declared distribution rate and suspension of distributions. We paid $78.4 million to Memorial Resource in connection with the Property Swap in February 2015. Capital contributions received from the previous owners were $1.9 million during 2015.    

During 2016, we repurchased an aggregate principal amount of approximately $26.4 million of the 2021 Senior Notes and $14.9 million of the 2022 Senior Notes. During 2015, we repurchased a principal amount of approximately $3.0 million of the 2022 Senior Notes in January 2015, of which $2.9 million was classified as a financing outflow representing repayment of the original proceeds and $0.3 million classified as an operating inflow.

During 2016, we sold approximately 1.2 million common units under an at-the-market program and generated net proceeds of $1.8 million. During 2015, we repurchased $54.2 million in common units, which represented a repurchase and retirement of 3,641,721 common units under the December 2014 repurchase program. This repurchase program expired in December 2015. See Note 10 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information.

The Partnership had net repayments of $324.3 million under its revolving credit facility during 2016. The Partnership had net borrowings of $424.0 million under its revolving credit facility during 2015 that were primarily used to fund a common control acquisition transaction and to fund its drilling program. Deferred financing costs of approximately $1.4 million were incurred during 2016 compared to approximately $0.3 million during 2015.

Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net income decreased by $511.1 million and net cash provided by operating activities decreased by $37.5 million. Production increased 9.8 Bcfe (approximately 12%) and the average realized sales price decreased to $3.85 per Mcfe as previously discussed under “—Results of Operations.” Cash paid for interest during 2015 was $107.3 million compared to $63.7 million during 2014. Net cash provided by operating activities in 2015 included $250.0 million of cash receipts on expired derivative instruments and we had a $19.7 million decrease in cash flow attributable to the timing of cash receipts and disbursements related to operating activities during 2015 compared to 2014.

Investing Activities. Net cash used in investing activities during 2015 was $337.6 million, of which $100.7 million was used to acquire oil and natural gas properties from third parties and $241.3 million was used for additions to oil and gas properties. Cash used in investing activities during 2014 was $1.39 billion, of which $1.08 billion was used to acquire oil and natural gas properties from third parties and $298.3 million was used for additions to oil and gas properties. We received a post-closing settlement receipt of $9.6 million related to the July 2014 Wyoming acquisition during 2015. See Note 4 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information regarding acquisitions and divestitures.

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our offshore Southern California oil and gas properties. During 2015 and 2014, additions to restricted investments were $5.7 million and $4.0 million, respectively. See Note 8 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our restricted investments.

Financing Activities. Distributions to partners during 2015 were $163.3 million compared to $154.9 million during 2014. The increase is primarily due to an increase in the number of outstanding units between periods partially offset by a decrease in the distribution paid during the fourth quarter of 2015. We paid $78.4 million to Memorial Resource in connection with the Property Swap in February 2015. We paid $33.9 million to an operating subsidiary of MRD LLC in April 2014 to acquire certain oil and natural gas properties in East Texas. In October 2014, we paid $15.0 million to acquire oil and gas properties in the Rockies from Memorial Resource. Capital contributions received from the previous owners were $1.9 million and $6.0 million during 2015 and 2014, respectively. The previous owners made distributions of $9.9 million during 2014 related to Classic.

During 2014, we issued a total of 24,840,000 common units generating gross proceeds of approximately $553.3 million, offset by approximately $12.5 million of costs incurred in conjunction with the issuance of common units. The net proceeds from these issuances, including our general partner’s proportional capital contributions, were primarily used to repay borrowings on our revolving credit facility.

81


We repurchased $54.2 million in common units during 2015, which represented a repurchase and retirement of 3,641,721 common units under the December 2014 repurchase program (including common unit repurchases of $1.4 million, representing 93,800 common units, accrued at December 31, 2014).  We repurchased a principal amount of approximately $3.0 million of the 2022 Senior Notes at a price of 83.000% of the face value of the 2022 Senior Notes in January 2015, of which $2.9 million was classified as a financing outflow representing repayment of the original proceeds and $0.3 million classified as an operating inflow.

Proceeds of $492.4 million from the issuances of our 2022 Senior Notes during 2014 were used to repay portions of our borrowings outstanding under our revolving credit facility and other general partnership purposes. See Note 9 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our Senior Notes.

The Partnership had net borrowings of $424.0 million under its revolving credit facility during 2015 that were primarily used to fund: (i) the purchase of the remaining interest in the Beta properties from a third party in November 2015, (ii) the Property Swap, (iii) common unit repurchases and (iv) its drilling program. The Partnership had borrowings of $1.45 billion under its revolving credit facility during 2014 that were used primarily to fund the Eagle Ford and Wyoming acquisitions and to fund its drilling program. Deferred financing costs of approximately $0.3 million were incurred during 2015 compared to approximately $11.5 million during 2014.

Capital Requirements

See “— Outlook” for additional information regarding our capital spending program for 2017.

Contractual Obligations

In the table below, we set forth our contractual obligations as of December 31, 2016. The contractual obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.

 

 

 

 

 

 

Payment or Settlement due by Period

 

Contractual Obligation

 

Total

 

 

Less than 1 year

 

 

1-3 years

 

 

3-5 years

 

 

Thereafter

 

 

 

 

 

 

 

(in thousands)

 

Revolving credit facility (1)

 

$

511,652

 

 

$

 

 

$

511,652

 

 

$

 

 

$

 

Senior Notes (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2021 Senior Notes

 

 

876,257

 

 

 

49,279

 

 

 

98,559

 

 

 

65,706

 

 

 

662,713

 

2022 Senior Notes

 

 

678,074

 

 

 

31,966

 

 

 

63,933

 

 

 

63,933

 

 

 

518,242

 

Estimated interest payments (3)

 

 

37,069

 

 

 

16,475

 

 

 

20,594

 

 

 

 

 

 

 

Asset retirement obligations (4)

 

 

131,701

 

 

 

3,024

 

 

 

5,593

 

 

 

4,360

 

 

 

118,724

 

CO2 minimum purchase commitment (5)

 

 

19,665

 

 

 

6,740

 

 

 

9,115

 

 

 

3,810

 

 

 

 

Operating leases (6)

 

 

24,922

 

 

 

7,938

 

 

 

8,366

 

 

 

5,831

 

 

 

2,786

 

Midstream services (7)

 

 

30,668

 

 

 

5,121

 

 

 

10,213

 

 

 

10,227

 

 

 

5,107

 

Total

 

$

2,310,007

 

 

$

120,543

 

 

$

728,025

 

 

$

153,867

 

 

$

1,307,573

 

 

(1)

Represents the scheduled future maturities of principal amount outstanding for the periods indicated. Maturities are shown at original maturity dates assuming no acceleration, however due to a default and event of default and the uncertainty regarding anticipated financial covenant violations, the Partnership’s entire long-term debt was classified as current at December 31, 2016. See Note 9 of the Notes to Consolidated and Combined Financial Statements included under Item 8 of this annual report for information regarding our revolving credit facility.

(2)

Represents the scheduled future interest payments on the 2021 Senior Notes and 2022 Senior Notes and principal payments. Interest accrues per annum and is payable semi-annually in arrears. Maturities are shown at original maturity dates assuming no acceleration, however due to a default and event of default and the uncertainty regarding anticipated financial covenant violations, the Partnership’s entire long-term debt was classified as current at December 31, 2016. See Note 9 of the Notes to Consolidated and Combined Financial Statements included under Item 8 of this annual report for additional information.

(3)

Estimated interest payments are based on the principal amount outstanding under our revolving credit facility at December 31, 2016. In calculating these amounts, we applied the weighted-average interest rate during 2016 associated with such debt. See Note 9 of the Notes to Consolidated and Combined Financial Statements included under Item 8 of this annual report for the weighted-average variable interest rate charged during 2016 under our revolving credit facility. In addition, our estimate of payments for interest gives effect to interest rate swap agreements that were in place at December 31, 2016. Maturities are shown at original maturity dates assuming no acceleration, however due to a default and event of default and the uncertainty regarding anticipated financial covenant violations, the Partnership’s entire long-term debt was classified as current at December 31, 2016.

(4)

Asset retirement obligations represent estimated discounted costs for future dismantlement and abandonment costs. These obligations are recorded as liabilities on our December 31, 2016 balance sheet. See Note 7 of the Notes to Consolidated and Combined Financial Statements included under Item 8 of this annual report for additional information regarding our asset retirement obligations.

(5)

Represents a firm agreement to purchase CO2 volumes related to our Bairoil properties in Wyoming.

(6)

Primarily represents leases for offshore Southern California right-of-way use and office space as well as equipment rentals. See Note 14 of the Notes to Consolidated and Combined Financial Statements included under Item 8 of this annual report for information regarding our operating leases.

(7)

Represents processing fees associated with a minimum volume commitment related to certain of our properties located in East Texas.

Off–Balance Sheet Arrangements

As of December 31, 2016, we had no off–balance sheet arrangements.

82


Recently Issued Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see Note 3 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data”.

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 primarily with lenders under our Credit Agreement. Historically, the Partnership has not paid or received premiums for options. In December 2016, in connection with our restructuring efforts, we monetized approximately $191.4 million in commodity hedges and settled $2.1 million in interest rate swaps prior to the Petition Date and used a significant portion of the proceeds to reduce amounts outstanding under our prepetition revolving credit facility. During the period of April and June 2016, we monetized approximately $39.3 million in commodity hedges and utilized the proceeds to buy back senior notes.

In January 2017, in connection with our restructuring efforts, we monetized $94.1 million in commodity hedges and used a portion of the proceeds to repay outstanding borrowings under our revolving credit facility and kept the remaining portion as cash on hand for general partnership purposes.

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, 2016, we did not have any outstanding collars.

The following table summarizes our derivative contracts as of December 31, 2016 and the average prices at which the production will be hedged:

 

2017

 

 

2018

 

 

2019

 

Natural Gas Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

Fixed price swap contracts:

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

1,890,000

 

 

 

1,740,000

 

 

 

1,000,000

 

Weighted-average fixed price

$

3.86

 

 

$

3.83

 

 

$

3.47

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

Fixed price swap contracts:

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

184,500

 

 

 

182,000

 

 

 

70,000

 

Weighted-average fixed price

$

84.29

 

 

$

83.44

 

 

$

86.84

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

Fixed price swap contracts:

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

43,300

 

 

 

 

 

 

 

Weighted-average fixed price

$

37.55

 

 

$

 

 

$

 

 

83


The following table summarizes our derivative contracts as of December 31, 2015 and the average prices at which the production was hedged:

 

2016

 

 

2017

 

 

2018

 

 

2019

 

Natural Gas Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed price swap contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

3,592,442

 

 

 

3,350,067

 

 

 

3,060,000

 

 

 

2,814,583

 

Weighted-average fixed price

$

4.14

 

 

$

4.06

 

 

$

4.18

 

 

$

4.31

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

3,578,333

 

 

 

2,210,000

 

 

 

1,315,000

 

 

 

900,000

 

Spread

$

(0.07

)

 

$

(0.04

)

 

$

(0.02

)

 

$

0.01

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed price swap contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

304,813

 

 

 

301,600

 

 

 

312,000

 

 

 

160,000

 

Weighted-average fixed price

$

85.48

 

 

$

85.00

 

 

$

83.74

 

 

$

85.52

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

140,000

 

 

 

67,500

 

 

 

 

 

 

 

Spread

$

(10.02

)

 

$

(7.82

)

 

$

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed price swap contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

213,100

 

 

 

43,300

 

 

 

 

 

 

 

Weighted-average fixed price

$

35.64

 

 

$

37.55

 

 

$

 

 

$

 

 

Our basis swaps as of December 31, 2015 included in the table above are presented on a disaggregated basis below:

 

2016

 

 

2017

 

 

2018

 

 

2019

 

Natural Gas Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NGPL TexOk basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

3,003,333

 

 

 

1,800,000

 

 

 

1,200,000

 

 

 

900,000

 

Spread - Henry Hub

$

(0.07

)

 

$

(0.07

)

 

$

(0.03

)

 

$

0.01

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

HSC basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

135,000

 

 

 

115,000

 

 

 

115,000

 

 

 

 

Spread - Henry Hub

$

0.07

 

 

$

0.14

 

 

$

0.15

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CIG basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

170,000

 

 

 

 

 

 

 

 

 

 

Spread - Henry Hub

$

(0.30

)

 

$

 

 

$

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TETCO STX basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

270,000

 

 

 

295,000

 

 

 

 

 

 

 

Spread - Henry Hub

$

0.06

 

 

$

0.03

 

 

$

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Midway-Sunset basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

100,000

 

 

 

37,500

 

 

 

 

 

 

 

Spread - WTI

$

(12.29

)

 

$

(12.20

)

 

$

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Midland basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

40,000

 

 

 

30,000

 

 

 

 

 

 

 

Spread - WTI

$

(4.34

)

 

$

(2.35

)

 

$

 

 

$

 

The change in volumes between the current and preceding fiscal year is primarily due to monetized hedges during 2016.

Interest Rate Risk

At December 31, 2016, we had $511.7 million of debt outstanding under our revolving credit facility, with a LIBOR Market Index Rate plus 2.25%, or 3.25%. 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.

84


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. During December 2016, in connection with our restructuring efforts, we elected to terminate the interest rate swaps associated with our revolving credit facility and in the aggregate paid our counterparties approximately $2.1 million. The Partnership did not have any interest rate swaps at December 31, 2016.

At December 31, 2015, we had the following interest rate open swap positions:

 

2016

 

 

2017

 

 

2018

 

Average Monthly Notional (in thousands)

$

400,000

 

 

$

400,000

 

 

$

100,000

 

Weighted-average fixed rate (1)

 

0.943

%

 

 

1.612

%

 

 

1.946

%

Floating rate

1 Month LIBOR

 

 

1 Month LIBOR

 

 

1 Month LIBOR

 

 

 

(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):

 

 

December 31, 2016

 

 

 

Carrying

 

 

Estimated

 

Description

 

Amount

 

 

Fair Value

 

2021 Senior Notes, fixed-rate, due May 1, 2021

 

$

646,287

 

 

$

314,257

 

2022 Senior Notes, fixed-rate due August 1, 2022

 

 

464,965

 

 

 

223,183

 

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, 2016, 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, 2016, after taking into effect netting arrangements, we had counterparty exposure of $64.9 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 $107.2 million against amounts outstanding under our revolving credit facility at December 31, 2016.

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, 2016 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.

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 F-1 of this annual report.

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ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

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, 2016.

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, 2016 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, 2016. The report, which expresses an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2016, 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, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

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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, 2016, 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, 2016, 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 sheets of Memorial Production Partners LP and subsidiaries as of December 31, 2016 and 2015, the related consolidated statements of operations, equity, and cash flows for the year ended December 31, 2016, and the related consolidated and combined statements of operations, equity, and cash flows for each of the years in the two-year period ended December 31, 2015, and our report dated March 10, 2017 expressed an unqualified opinion on those consolidated and combined financial statements.

 

/s/ KPMG LLP

Houston, Texas

March 10, 2017

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ITEM  9B.

OTHER INFORMATION

None

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PART III

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 the Partnership. 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.

Our general partner has a board of directors that oversees its management, operations and activities. The board of directors currently has five 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. Historically, unitholders were not entitled to elect the directors of our general partner. Following the MEMP GP Acquisition, for so long as the Partnership owns a majority of the membership interests of MEMP GP, the limited partners of the Partnership will elect the members of the general partner’s board of directors beginning with our next annual meeting. The board of directors is divided into three classes, with Mr. W. Donald Brunson designated as a Class I director with a term expiring at the 2017 annual meeting, Messrs. P. Michael Highum and William J. Scarff designated as Class II directors with terms expiring at the 2018 annual meeting, and Messrs. Jonathan M. Clarkson and John A. Weinzierl designated as Class III directors with terms expiring at the 2019 annual meeting.

In light of the Chapter 11 proceedings and the plan of reorganization that the Debtors are seeking to confirm in connection therewith, it is unlikely that we will hold an annual meeting of our unitholders in 2017. In addition, if (as we expect) we emerge from the Chapter 11 proceedings as a corporation, we will be required to comply with the NASDAQ listing requirements applicable to corporations.

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. Jonathan M. Clarkson serves as the Non-Executive Chairman of the board of directors of our general partner. We do not have a policy requiring either that the positions of the Chairman of the board and the Chief Executive Officer, be separate or that they be occupied by the same individual. The board of directors of our general partner believes that this issue is properly addressed as part of the succession planning process and that a determination on this subject should be made when it elects a new chief executive officer or at such other times as when consideration of the matter is warranted by circumstances.

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 March 1, 2017.

Name

 

Age

 

Position with our General Partner

William J. Scarff

 

61

 

President, Chief Executive Officer and Director

Christopher S. Cooper

 

49

 

Senior Vice President and Chief Operating Officer

Robert L. Stillwell, Jr.

 

39

 

Vice President and Chief Financial Officer

Jason M. Childress

 

37

 

Vice President, General Counsel and Corporate Secretary

Matthew J. Hoss

 

34

 

Vice President, Accounting

Jonathan M. Clarkson

 

67

 

Non-Executive Chairman and Director

W. Donald Brunson

 

72

 

Director

P. Michael Highum

 

66

 

Director

John A. Weinzierl

 

48

 

Director

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.

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William J. Scarff has served as our general partner’s President and Chief Executive Officer since September 2016, and prior to that, he served as President of our general partner since January 2014 and as a member of the board of directors of our general partner since March 2016. 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 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.

The board believes Mr. Scarff’s extensive executive experience with oil and natural gas companies brings valuable strategic, managerial and analytical skills to the board and us.

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.

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.

Jason M. Childress has served as our general partner’s Vice President, General Counsel and Corporate Secretary since July 2015. Mr. Childress served as the Assistant General Counsel and Assistant Secretary of Memorial Resource from January 2014 to May 2016 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 LLP. Prior to that, he held various positions in the audit practice at PricewaterhouseCoopers LLP.

Matthew J. Hoss has served as our general partner’s Vice President, Accounting since May 2016. Previously he served as Controller of Memorial Resource from January 2015 to April 2016, Director, Accounting from July 2014 to December 2014, Director, Accounting of MRD LLC from January 2014 to June 2014 and Manager, Special Projects from May 2012 to December 2013. Prior to joining MRD LLC, Mr. Hoss held various positions from September 2006 to May 2012 in the transaction services and assurance practices at PricewaterhouseCoopers LLP in Houston, Texas, primarily serving energy clients. Mr. Hoss is a Certified Public Accountant.

Jonathan M. Clarkson has served as Chairman of the board of directors of our general partner since September 2016 and as a member of the board of directors since December 2011. Mr. Clarkson served as Chief Financial Officer for Matrix Oil Corporation from May 2012 until his retirement in January 2016. 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. Mr.Clarkson also currently serves on the board of directors of Wildhorse Resource Development Corp., which service began in December 2016. He is also the chairman of the audit committee of Wildhorse Resource Development Corp. 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.

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W. Donald Brunson has served as a member of the board of directors of our general partner since December 2014. Prior to his retirement in 2012, Mr. Brunson 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.

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.

John A. Weinzierl has served as a member of the board of directors of our general partner since April 2011. He served as our general partner’s Chief Executive Officer and Chairman of the board of directors from January 2014 until September 2016. 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 to December 2011. 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 bring valuable strategic, managerial and analytical skills to the board and us.

Composition of the Board of Directors

Our general partner’s board of directors consists of five 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.

Board Nominations; Consideration of Diversity

Following the MEMP GP Acquisition, our partnership agreement provides that nominations of persons for election to the board of directors of our general partner may be made at an annual meeting of the limited partners only pursuant to our general partner’s notice of the meeting, (1) by or at the direction of a majority of the directors on the board of directors, or (2) by any limited partner or group of limited partners that holds or beneficially owns, and has continuously held or beneficially owned without interruption for the prior 36 months, at least 3% of our outstanding units; provided that such limited partner, or each limited partner in such group, was a record holder at the time the notice provided for in our partnership agreement was delivered to our general partner and complies with the notice procedures set forth in our partnership agreement.

Historically, the owners of our general partner did not apply a formal diversity policy or set of guidelines in selecting and appointing directors to the board of directors. However, when appointing new directors, the owners of our general partner considered each individual director’s qualifications, skills, business experience and capacity to serve as a director, as described above for each director, and the diversity of these attributes for the board of directors as a whole. When considering new director nominees, our board of directors will utilize these same considerations.

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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 1600, 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 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 2016.

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. 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, 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 11 meetings in 2016.

Meetings and Other Information

The board of directors of our general partner meets regularly to review significant developments affecting us and to act on matters requiring its approval. The board of directors held 25 meetings in 2016. None of the directors attended fewer than 75% of the aggregate number of meetings of the board of directors of our general partner and committees of the board of directors on which the director served.

We believe that there are benefits to having members of the board of directors of our general partner attend annual meetings, and we will strongly encourage all of the directors and nominees for director to attend the annual meetings; however, attendance is not mandatory.

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In light of the Chapter 11 proceedings and the plan of reorganization that the Debtors are seeking to confirm in connection therewith, it is unlikely that we will hold an annual meeting of our unitholders in 2017.

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 MEMP GP, we believe that during the year ended December 31, 2016 the officers and directors of MEMP GP 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 1600, Houston, Texas 77002 or made by telephone at (713) 588-8346. 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 Form 8-K. 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, may be reimbursed.

Prior to June 1, 2016, we had an omnibus agreement with a wholly-owned subsidiary of Memorial Resource, pursuant to which management, administrative and operational services were provided to our general partner and us to manage and operate our business. Our general partner had reimbursed Memorial Resource, on a monthly basis, for the allocable expenses it incurred in its performance under the omnibus agreement, and we reimbursed our general partner for such payments it made to Memorial Resource. These expenses included, among other things, salary, bonus, incentive compensation and other amounts paid to persons who performed services for us or on our behalf and other expenses allocated to our general partner. We believed the expenses to be no more than those we would had been required to pay if we received services from an unaffiliated third party. Memorial Resource had 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 provided that our general partner determined in good faith the expenses that are allocable to us. In connection with the MEMP GP Acquisition, we terminated the omnibus agreement. See “Item 13. Certain Relationships and Related Transactions, and Director Independence — Related Party Agreements — Omnibus Agreement.”

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ITEM 11.

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

This compensation discussion and analysis provides an overview of the 2016 executive compensation program for our general partner’s named executive officers (“NEOs”) identified below.

Name

 

Principal Position

William J. Scarff

 

President and Chief Executive Officer

Christopher S. Cooper

 

Senior Vice President and Chief Operating Officer

Robert L. Stillwell, Jr.

 

Vice President and Chief Financial Officer

Jason M. Childress

 

Vice President, General Counsel and Corporate Secretary

Matthew J. Hoss

 

Vice President, Accounting

John A. Weinzierl (1)

 

Director (former Chairman and Chief Executive Officer)

 

 

(1)

Mr. Weinzierl resigned from being the Chairman and Chief Executive Officer in September 2016.

Our Compensation Philosophy

The Partnership employs a compensation philosophy that emphasizes pay-for-performance 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. Our general partner’s executive compensation is designed 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

Prior to the MEMP GP Acquisition. Prior to the MEMP GP Acquisition, all of our general partner’s executive officers and other personnel necessary for our business to function were employed and compensated by our general partner or Memorial Resource, in each case subject to reimbursement by us. Memorial Resource managed our operations and activities, and made certain compensation decisions on our behalf, under the omnibus agreement. The compensation for all of our general partner’s executive officers was paid by Memorial Resource, and we reimbursed Memorial Resource for costs and expenses incurred for our benefit or on our behalf pursuant to the terms of the omnibus agreement.

Responsibility and authority for compensation-related decisions for executive officers and other personnel that were employed by Memorial Resource resided with Memorial Resource. Our general partner’s executive officers managed 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 was 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 were made by the board of directors of our general partner, following the recommendation of Memorial Resource.  

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 2016, 2015 and 2014.

After the MEMP GP Acquisition. Following the MEMP GP Acquisition, the board of directors of our general partner has the sole responsibility for approving and evaluating the director and executive officer compensation plans, policies and programs of the Partnership. The board of directors uses several different tools and resources in reviewing elements of executive compensation and making compensation decisions, including the compensation consultant noted below. These decisions, however, are not purely formulaic and the board of directors exercises judgment and discretion as appropriate. The board of directors considers input from the Chief Executive Officer of our general partner (our “CEO”) in making determinations regarding our executive compensation program and the individual compensation of each executive officer, other than our CEO. Our CEO and management also provide information to the board of directors regarding the performance of the Partnership for the determination by the board of directors of annual bonuses. The board of directors makes the final determination of NEO compensation. Our CEO makes no recommendations regarding, and does not participate in discussions about, his own compensation.

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The Partnership, at the direction of the board of directors of our general partner, engaged Pearl Meyer & Partners, LLC (“Pearl Meyer”) as the Partnership’s independent compensation consultant to provide recommendations regarding our executive compensation arrangements in 2016. Pearl Meyer reports directly to the board of directors and with the consent of the board of directors, coordinates and gathers information with which to advise the board of directors from members of management. Pearl Meyer assists the board of directors with its review of the Partnership’s executive and director compensation programs including, without limitation: (i) recommending the most appropriate peer group, (ii) examining competitive levels of base salary, annual incentives, total cash compensation, long-term incentives, and total direct compensation of the executive officers of our general partner against the chosen peer group, (iii) comparing the compensation of the Partnership’s executive team to market data to determine current posture relative to the competitive market, (iv) analyzing how peer companies effectively deliver compensation to their executive officers in terms of overall mix and program design, (v) developing initial recommendations as to the amount and form of compensation to be paid to the executive officers of our general partner, (vi) developing initial recommendations as to the design/construct of the Partnership’s go-forward annual incentive (bonus) and long-term incentive programs, and (vii) assisting in the implementation of the short- and long-term incentive programs, including addressing any ongoing concerns.

The board of directors of our general partner selected peer companies reflecting the range of market capitalization of the Partnership over the last several years and similar lines of business to the Partnership (i.e., independent exploration and production companies). The peer group may change from time to time as a result of fluctuations in company size, changes in the business lines of our peers, acquisitions, developments in the oil and gas industry and other factors. The peer group used by the board of directors in making 2016 compensation decisions consisted of the following companies: Whiting Petroleum Corp.; SM Energy Company; Denbury Resources Inc.; EP Energy Corporation; Energen Corp.; Oasis Petroleum Inc.; Breitburn Energy Partners LP; Laredo Petroleum, Inc.; Rice Energy Inc.; Stone Energy Corp.; Carrizo Oil & Gas Inc.; Vanguard Natural Resources, LLC; PDC Energy, Inc.; Legacy Reserves LP; EXCO Resources Inc.; Parsley Energy, Inc.; Bonanza Creek Energy, Inc.; Comstock Resources Inc.; Bill Barrett Corp.; and Northern Oil and Gas, Inc.

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.

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. We review the base salaries on an annual basis and may make adjustments as necessary to maintain a competitive executive compensation structure. As part of our review, we may examine the compensation of executive officers in similar positions with similar responsibilities at peer companies identified by us 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. We review 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, we meet 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.  The board of directors considers and takes into account several factors in determining the discretionary bonus awards such as production, operating expenses, safety/environmental, general and administrative expenses and management and strategic initiatives.

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 who perform services for us. Each of our general partner’s named executive officers is eligible to participate in our LTIP. We determine the overall amount of all long-term equity incentive compensation to be granted annually for our 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. Our LTIP is administered by a plan administrator, which is currently the board of directors of our general partner.

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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, 2016, only 194,905 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, 2016, our general partner’s named executive officers and independent directors were granted awards of phantom units as indicated in the following table:

 

 

Aggregate Number

 

Award Recipient

 

of Phantom Units

 

William J. Scarff

 

 

670,391

 

Christopher S. Cooper

 

 

558,659

 

Robert L. Stillwell, Jr.

 

 

363,128

 

Jason M. Childress

 

 

335,196

 

Matthew J. Hoss

 

 

139,665

 

Jonathan M. Clarkson

 

 

51,867

 

P. Michael Highum

 

 

51,867

 

W. Donald Brunson

 

 

51,867

 

John A. Weinzierl (1)

 

 

1,005,587

 

 

 

(1)

All of Mr. Weinzierl’s phantom units were received as an executive officer.

The board of directors of our general partner determines any awards made under our LTIP. With regard to the awards made during 2016, the board of directors took a number of factors into account, including, among others, the significant operational improvements over the course of the prior twelve months; the significant transactions completed by the Partnership, including the MEMP GP Acquisition and the 2015 Beta Acquisition; 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.

Restricted or phantom unit awards are 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.

Key Employee Incentive Plan and Key Employee Retention Program. In October 2016, the board of directors of our general partner approved the adoption of a key employee incentive plan and a key employee retention program for the benefit of certain employees identified by the board of directors, including the named executive officers, whose continued employment and performance is critical to the success of our general partner and the Partnership. In adopting the plans, the board of directors relied upon the market analysis and advice of Pearl Meyer.

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Under the key employee incentive plan, the Partnership may make cash bonus payments to specified key employees, including the named executive officers of the Partnership. Participants in the plan will be eligible to receive quarterly cash bonus payments based upon the achievement of pre-established performance measures relating to lease operating expenses, oil and gas production and workplace safety, and such other measures as may be designated by the board of directors. The quarterly bonuses potentially payable to William J. Scarff, Christopher S. Cooper, Robert L. Stillwell, Jr., Jason M. Childress and Matthew J. Hoss, measured at the target level of performance, would be $350,000, $200,000, $200,000, $200,000, and $75,000, respectively. The actual amount payable may be more or less than the target amount, depending upon performance. The key employee incentive plan was effective for the Partnership’s fiscal quarter ending December 31, 2016 and is effective for future fiscal quarters in 2017, unless terminated by the board.

Under the key employee retention program, the Partnership made cash retention payments to specified key employees, including the named executive officers of the Partnership. Participants in the program were eligible to receive lump sum retention payments upon entering into a participation agreement with the Partnership. Under the agreement, retention payments are subject to a repayment “clawback” by the Partnership in the event that the participant terminates employment prior to the occurrence of certain specified events, or expiration of 12 months from the date of the agreements, if later, and subject to exceptions for terminations of employment under certain circumstances. The cash retention bonuses paid (subject to clawback) to Messrs. Scarff, Cooper, Stillwell, Childress and Hoss were $800,000, $675,000, $625,000, $575,000, and $100,000, respectively. Mr. Hoss is eligible to receive an additional cash bonus of $100,000 upon the occurrence of certain specified events or expiration of 12 months from the date of the agreement, if later.

Severance and Change in Control Benefits. On May 4, 2016, we entered into change of control agreements with the executive officers of our general partner. These change of control agreements require our general partner to provide certain compensation and benefits to such officers if such officer’s employment is terminated on account of a qualifying termination (as defined below). The change of control agreements continue in effect until the earlier of (i) a separation from service other than on account of a qualifying termination, (ii) our general partner’s satisfaction of all of its obligations under the change of control agreement, or (iii) the execution of a written agreement between our general partner and the executive officer terminating the change of control agreement.

Under the terms of each change of control agreement, if an executive’s employment is terminated on account of a qualifying termination, then subject to such executive’s signing and not revoking a separation agreement and release of claims, then such executive will be entitled to:

 

receive a lump sum payment equal to a specified percentage of such executive’s (i) annual base salary and (ii) target bonus, in each case, at the highest rate in effect during the twelve month period prior to the date in which the qualifying termination occurs, which percentage is 250/200/150%;

 

the vesting of all outstanding unvested awards previously granted to such executive under the LTIP;

 

reimbursement for the amount of COBRA continuation premiums (less required co-pay) until the earlier of (a) twelve months following the qualifying termination and (b) such time as such executive is no longer eligible for COBRA continuation coverage;

 

financial counseling services for twelve months following the qualifying termination, subject to a maximum benefit of $30,000; and

 

outplacement counseling services for twelve months following the qualifying termination, subject to a maximum value of $30,000.

“Qualifying termination” means, as to any executive, the separation of service on account of (i) an involuntary termination by our general partner without “cause” or (ii) such executive’s voluntary resignation for “good reason”, in each case, within six months prior to, or twenty-four months following, a change of control. The term “cause” means (i) such executive’s commission of, conviction for, plea of guilty or nolo contendere to a felony or a crime involving moral turpitude; (ii) engaging in conduct that constitutes fraud, gross negligence or willful misconduct that results or would reasonably be expected to result in material harm to the Partnership or its affiliates or their respective businesses or reputations; (iii) breach of any material terms of such executive’s employment, including any of our general partner’s policies or code of conduct; or (iv) willful and continued failure to substantially perform such executive’s duties for our general partner which such failure is not remedied within ten business days after receipt of written demand of substantial performance by the board of directors of our general partner. The term “good reason” means the occurrence of one of the following without an executive’s express written consent (i) a material reduction of such executive’s duties, position or responsibilities, or such executive’s removal from such position and responsibilities, unless such executive is offered a comparable position (i.e., a position of equal or greater organizational level, duties, authority, compensation, title and status); (ii) a material reduction by our general partner of such executive’s base compensation (base salary and target bonus) as in effect immediately prior to such reduction; (iii) such executive is requested to relocate (except for office relocations that would not increase such executive’s one way commute by more than 50 miles); or (iv) any other action or inaction that constitutes a material breach by our general partner of the change of control agreement. The term “change of control” has the meaning ascribed to such term in the LTIP; provided that a change of control shall be deemed not to have occurred if the Partnership acquires our general partner.

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In the event that the board of directors of our general partner determines that payments to be made to an executive under the change of control agreement would constitute “excess parachute payments” subject to excise tax under Section 4999 of the Internal Revenue Code, then the amount of such payments shall either (i) be reduced so that such payments will not be subject to such excise tax or (ii) paid in full, whichever results in the better net after tax position for the executive.

Other Benefits. We do not maintain a defined benefit pension plan for the executive officers of our general partner, because it believes such plans primarily reward longevity rather than performance. We provide a basic benefits package generally to all employees, which includes a 401(k) plan and health, disability and life insurance.

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

 

Jonathan M. Clarkson

W. Donald Brunson

P. Michael Highum

John A. Weinzierl

William J. Scarff

Employment Agreements

Our general partner has not 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

Our 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.

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Summary Compensation Table

The following table includes the compensation earned by our general partner’s named executive officers for the years ended December 31, 2016, 2015 and 2014.

 

 

 

 

 

 

 

 

 

 

 

 

Equity

 

 

All Other

 

 

 

 

 

Name and Position

 

Year

 

Salary (6)

 

 

Bonus

 

 

Awards (7)

 

 

Compensation (8)

 

 

Total

 

William J. Scarff

 

2016

 

$

327,500

 

 

$

800,000

 

 

$

1,200,000

 

 

$

56,234

 

 

$

2,383,734

 

President and Chief Executive Officer

 

2015

 

 

175,000

 

 

 

112,000

 

 

 

574,996

 

 

 

190,917

 

 

 

1,052,913

 

 

 

2014

 

 

153,542

 

 

 

176,458

 

 

 

1,999,990

 

 

 

108,250

 

 

 

2,438,240

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Christopher S. Cooper

 

2016

 

$

322,083

 

 

$

675,000

 

 

$

1,000,000

 

 

$

38,081

 

 

$

2,035,165

 

Senior Vice President and Chief Operating Officer (1)

 

2015

 

 

175,000

 

 

 

112,000

 

 

 

900,000

 

 

 

96,792

 

 

 

1,283,792

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Robert L. Stillwell, Jr.

 

2016

 

$

298,125

 

 

$

625,000

 

 

$

650,000

 

 

$

37,258

 

 

$

1,610,383

 

Vice President and Chief Financial Officer (2)

 

2015

 

 

162,500

 

 

 

100,000

 

 

 

750,003

 

 

 

82,491

 

 

 

1,094,994

 

 

 

2014

 

 

123,750

 

 

 

96,250

 

 

 

250,007

 

 

 

44,830

 

 

 

514,837

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Jason M. Childress (3)

 

2016

 

$

253,125

 

 

$

575,000

 

 

$

600,000

 

 

$

27,697

 

 

$

1,455,822

 

Vice President, General Counsel and Corporate Secretary

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Matthew J. Hoss (4)

 

2016

 

$

176,667

 

 

$

100,000

 

 

$

250,000

 

 

$

24,301

 

 

$

550,968

 

Vice President, Accounting

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

John A. Weinzierl (5)

 

2016

 

$

159,215

 

 

$

 

 

$

1,800,000

 

 

$

70,686

 

 

$

2,029,901

 

Director (former Chairman and Chief Executive Officer)

 

2015

 

 

212,500

 

 

 

112,000

 

 

 

975,009

 

 

 

407,021

 

 

 

1,706,530

 

 

 

2014

 

 

165,000

 

 

 

 

 

 

2,800,008

 

 

 

468,106

 

 

 

3,433,114

 

 

(1)

Mr. Cooper has served as Senior Vice President and Chief Operating Officer since November 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. Childress has served as Vice President, General Counsel, and Corporate Secretary since July 2015. Mr. Childress became a named executive officer in 2016.

(4)

Mr. Hoss has served as Vice President, Accounting since May 2016. Mr. Hoss became a named executive officer in 2016.

(5)

Mr. Weinzierl served as our CEO and Chairman of the board of directors until September 2016 and a member of the board of directors of our general partner since April 2011. Mr. Weinzierl’s salary for 2016 includes both salary related to being CEO of approximately $71,715 and compensation paid as a director of approximately $87,500.

(6)

Prior to June 1, 2016, salary and other compensation earned by our general partner’s executive officers was allocated to us by Memorial Resource and based on the terms as set forth by the MEMP GP Acquisition purchase and sale agreement for the period from April 1, 2016 through the closing date of the transaction. After June 1, 2016, salary earned by our general partner’s executive officers was paid directly by the Partnership.

(7)

Reflects the aggregate grant date fair value of restricted and/or phantom unit awards granted under the LTIP calculated by multiplying the number of restricted and/or phantom units granted to each executive by the closing price of our common units on date of grant. For information about assumptions made in the valuation of these awards, see Note 12 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.” The closing price of our common units at December 31, 2016 was $0.12 per unit.

(8)

Amounts include (i) matching contributions underfunded, 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.

The following supplemental table presents the components of “All Other Compensation” for each named executive officer for the year ended December 31, 2016:

 

 

Quarterly

 

 

 

 

 

 

 

 

 

 

 

Distributions

 

 

 

 

 

 

Total

 

 

 

Paid On

 

 

 

 

 

 

All Other

 

Name

 

Awards

 

 

Other (2)

 

 

Compensation

 

William J. Scarff

 

$

34,527

 

 

$

21,707

 

 

$

56,234

 

Christopher S. Cooper

 

 

24,149

 

 

 

13,932

 

 

 

38,081

 

Robert L. Stillwell, Jr.

 

 

19,940

 

 

 

17,318

 

 

 

37,258

 

Jason M. Childress

 

 

15,720

 

 

 

11,977

 

 

 

27,697

 

Matthew J. Hoss

 

 

5,553

 

 

 

18,748

 

 

 

24,301

 

John A. Weinzierl (1)

 

 

56,691

 

 

 

13,996

 

 

 

70,686

 

 

 

(1)

Mr. Weinzierl resigned from being the Chairman and Chief Executive Officer in September 2016.

 

(2)

Prior to June 1, 2016, other compensation earned by our general partner’s executive officers was allocated to us by Memorial Resource and based on the terms as set forth by the MEMP GP Acquisition purchase and sale agreement for the period from April 1, 2016 through the closing date of the transaction. After June 1, 2016, salary earned by our general partner’s executive officers was paid directly by the Partnership.

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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 2016.

 

 

 

 

All Other

 

 

 

 

 

 

 

 

 

Equity Awards:

 

 

Grant Date

 

 

 

 

 

Number of

 

 

Fair Value of Unit

 

 

 

 

 

Phantom Units

 

 

and Option Awards

 

Name

 

Grant Date

 

(#) (1)

 

 

($) (2)

 

William J. Scarff

 

06/14/16

 

 

670,391

 

 

 

1,200,000

 

Christopher S. Cooper

 

06/14/16

 

 

558,659

 

 

 

1,000,000

 

Robert L. Stillwell, Jr.

 

06/14/16

 

 

363,128

 

 

 

650,000

 

Jason M. Childress

 

06/14/16

 

 

335,196

 

 

 

600,000

 

Matthew J. Hoss

 

06/14/16

 

 

139,665

 

 

 

250,000

 

John A. Weinzierl (3)

 

06/14/16

 

 

1,005,587

 

 

 

1,800,000

 

 

 

(1)

Represents the amount of phantom 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 phantom unit awards granted under the LTIP calculated by multiplying the number of phantom 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 12 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.” See table below for the market value of such awards, in addition to other unvested awards at December 31, 2016.

 

(3)

Mr. Weinzierl resigned from being the Chairman and Chief Executive Officer in September 2016.

Outstanding Equity Awards

The following table sets forth certain information with respect to outstanding equity awards at December 31, 2016.

 

 

 

 

Restricted and Phantom

 

 

 

 

 

Unit Awards

 

 

 

 

 

Number of Units

 

 

Market Value of

 

 

 

 

 

That Have

 

 

Units That Have

 

 

 

Vesting

 

Not Vested

 

 

Not Vested

 

Name

 

Date (1)

 

(#)

 

 

($) (2)

 

William J. Scarff

 

Various

 

 

725,850

 

 

 

87,102

 

Christopher S. Cooper

 

Various

 

 

598,046

 

 

 

71,766

 

Robert L. Stillwell, Jr.

 

Various

 

 

400,320

 

 

 

48,038

 

Jason M. Childress

 

Various

 

 

357,442

 

 

 

42,893

 

Matthew J. Hoss

 

Various

 

 

144,515

 

 

 

17,342

 

John A. Weinzierl

 

Various

 

 

1,090,558

 

 

 

130,867

 

 

 

(1)

One-third vests on the first, second, and third anniversaries of each date of grant. Of the 3,331,834 non-vested restricted common unit and phantom unit awards presented in the table, approximately 1,201,107 vest in 2017, 1,106,521 vest in 2018 and 1,024,206 vest in 2019. There were 15,103 restricted common units that vested on January 9, 2017.

 

(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, 2016 of $0.12 per unit.

100


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 2016.

 

 

 

 

Restricted Common Unit Awards

 

 

 

 

 

Number of Units

 

 

Unit Price

 

 

Market Value of Units

 

Name

 

Vesting Date (1)

 

That Have Vested

 

 

On Vesting Date

 

 

That Have Vested

 

 

 

 

 

(#) (2)

 

 

 

 

 

 

($) (3)

 

William J. Scarff

 

05/29/16

 

 

12,829

 

 

$

2.11

 

 

 

27,069

 

 

 

05/30/16

 

 

29,802

 

 

$

2.11

 

 

 

62,882

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Christopher S. Cooper

 

01/09/16

 

 

11,327

 

 

$

2.41

 

 

 

27,298

 

 

 

05/29/16

 

 

8,367

 

 

$

2.11

 

 

 

17,654

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Robert L. Stillwell, Jr.

 

05/29/16

 

 

16,734

 

 

$

2.11

 

 

 

35,309

 

 

 

05/30/16

 

 

3,725

 

 

$

2.11

 

 

 

7,860

 

 

 

05/31/16

 

 

3,349

 

 

$

2.10

 

 

 

7,033

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Jason M. Childress

 

05/29/16

 

 

2,622

 

 

$

2.11

 

 

 

5,532

 

 

 

05/30/16

 

 

3,397

 

 

$

2.11

 

 

 

7,168

 

 

 

05/31/16

 

 

3,367

 

 

$

2.10

 

 

 

7,071

 

 

 

07/01/16

 

 

6,803

 

 

$

1.91

 

 

 

12,994

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Matthew J. Hoss

 

05/29/16

 

 

2,008

 

 

$

2.11

 

 

 

4,237

 

 

 

05/30/16

 

 

834

 

 

$

2.11

 

 

 

1,760

 

 

 

05/31/16

 

 

1,674

 

 

$

2.10

 

 

 

3,515

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

John A. Weinzierl

 

01/09/16

 

 

3,776

 

 

$

2.41

 

 

 

9,100

 

 

 

05/29/16

 

 

17,850

 

 

$

2.11

 

 

 

37,664

 

 

 

05/30/16

 

 

41,723

 

 

$

2.11

 

 

 

88,036

 

 

 

05/31/16

 

 

39,872

 

 

$

2.10

 

 

 

83,731

 

 

 

(1)

One-third vests on the first, second, and third anniversaries of each date of grant. There were 15,103 restricted common units that vested on January 9, 2017.

 

(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.

Nonqualified Deferred Compensation

Currently, our general partner does not, and does not intend to, sponsor or adopt a nonqualified deferred compensation plan.

101


Potential Payments Upon Termination or Change in Control

The following table sets forth information concerning the change in control and severance payments to be made to each of our named executive officers in connection with a change in control or termination of employment, presuming a termination or change in control date of December 31, 2016 and a valuation of our common units based on its closing market price of $0.12 per unit. The below table only includes information for employment termination or change in control events that trigger vesting or severance-related payments, and assumes that each executive will take all action necessary or appropriate for such person to receive the maximum available benefit, such as execution of a release of claims. Additional descriptions of the terms of our agreements, plans, and arrangements with our named executive officers are set forth in “Item 11. Executive Compensation — Elements of Executive Compensation.”

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.”

Name

 

Change in Control (with Termination without Cause or Voluntary Resignation for Good Reason

 

 

Voluntary Resignation (outside a Change in Control)

 

 

Termination without Cause (outside a Change of Control)

 

 

Termination for Cause

 

 

Termination due to Death or Disability

 

William J. Scarff

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Severance

 

$

3,000,000

 

 

$

 

 

$

 

 

$

 

 

$

 

Accelerated Equity Compensation

 

 

81,113

 

 

 

 

 

 

 

 

 

 

 

 

 

Health and Welfare Benefits

 

 

18,834

 

 

 

 

 

 

 

 

 

 

 

 

 

Financial Counseling

 

 

30,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Outplacement Assistance

 

 

30,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

3,159,947

 

 

$

 

 

$

 

 

$

 

 

$

 

Christopher S. Cooper

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Severance

 

$

1,691,000

 

 

$

 

 

$

 

 

$

 

 

$

 

Accelerated Equity Compensation

 

 

71,766

 

 

 

 

 

 

 

 

 

 

 

 

 

Health and Welfare Benefits

 

 

23,863

 

 

 

 

 

 

 

 

 

 

 

 

 

Financial Counseling

 

 

30,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Outplacement Assistance

 

 

30,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

1,846,629

 

 

$

 

 

$

 

 

$

 

 

$

 

Robert L. Stillwell, Jr.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Severance

 

$

1,577,000

 

 

$

 

 

$

 

 

$

 

 

$

 

Accelerated Equity Compensation

 

 

48,038

 

 

 

 

 

 

 

 

 

 

 

 

 

Health and Welfare Benefits

 

 

28,614

 

 

 

 

 

 

 

 

 

 

 

 

 

Financial Counseling

 

 

30,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Outplacement Assistance

 

 

30,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

1,713,652

 

 

$

 

 

$

 

 

$

 

 

$

 

Jason M. Childress

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Severance

 

$

918,750

 

 

$

 

 

$

 

 

$

 

 

$

 

Accelerated Equity Compensation

 

 

42,893

 

 

 

 

 

 

 

 

 

 

 

 

 

Health and Welfare Benefits

 

 

8,443

 

 

 

 

 

 

 

 

 

 

 

 

 

Financial Counseling

 

 

30,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Outplacement Assistance

 

 

30,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

1,030,086

 

 

$

 

 

$

 

 

$

 

 

$

 

Matthew J. Hoss

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Severance

 

$

528,750

 

 

$

 

 

$

 

 

$

 

 

$

 

Accelerated Equity Compensation

 

 

17,342

 

 

 

 

 

 

 

 

 

 

 

 

 

Health and Welfare Benefits

 

 

15,655

 

 

 

 

 

 

 

 

 

 

 

 

 

Financial Counseling

 

 

30,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Outplacement Assistance

 

 

30,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

621,747

 

 

$

 

 

$

 

 

$

 

 

$

 

102


Director Compensation

Officers or employees of our general partner or its affiliates, who also serve as directors of our general partner, including Scott A. Gieselman, Kenneth A. Hersh and Tony R. Weber, who each resigned from the board on March 4, 2016, 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, 2016.

 

 

Fees Earned

 

 

Phantom

 

 

All Other

 

 

 

 

 

 

 

or Paid in Cash

 

 

Unit Awards

 

 

Compensation

 

 

Total

 

Name

 

($)

 

 

($)(2)

 

 

(3)

 

 

($)

 

Jonathan M. Clarkson (1)

 

 

225,000

 

 

 

125,000

 

 

 

31,085

 

 

 

381,085

 

P. Michael Highum

 

 

181,250

 

 

 

125,000

 

 

 

31,085

 

 

 

337,335

 

W. Donald Brunson

 

 

181,250

 

 

 

125,000

 

 

 

27,798

 

 

 

334,048

 

 

(1)

Serves as chairman of the board and the audit committee.

(2)

Reflects the aggregate grant date fair value of phantom unit awards granted under the LTIP calculated by multiplying the number of phantom units granted to each director by the closing price of $0.12 per unit on December 31, 2016 with respect to the grants made to Messrs. Clarkson, Highum and Brunson on January 8, 2016. For information about assumptions made in the valuation of these awards, see Note 12 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data.” At December 31, 2016, Messrs. Clarkson, Highum, and Brunson had 51,867; 51,867; and 51,867 phantom units outstanding, respectively, that vested on January 8, 2017.

(3)

Represents quarterly distribution paid on LTIP Awards.

Phantom units were awarded to the non-employee directors in January 2016 with a one year vesting period. 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.

Effective in October 2016, the following compensation, payable at the beginning of each quarter, has been approved for the non-employee directors:

 

an annual retainer of $250,000 for each director;

 

a supplemental quarterly retainer of $25,000 for each director;

 

an annual retainer of $125,000 for the non-executive chairman of the board of directors; and

 

an annual retainer of $20,000 for the chairman of the audit committee.

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.

103


ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

As of January 31, 2017, 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.

 

 

 

Common Units

Beneficially

Owned

 

 

Percentage of

Common Units

Beneficially Owned

 

Name of Beneficial Owner (1)

 

(2)

 

 

(3)

 

Jonathan M. Clarkson

 

 

32,652

 

 

*

 

P. Michael Highum

 

 

20,242

 

 

*

 

W. Donald Brunson

 

 

16,666

 

 

*

 

John A. Weinzierl

 

 

570,856

 

 

*

 

William J. Scarff

 

 

109,476

 

 

*

 

Christopher S. Cooper

 

 

49,394

 

 

*

 

Robert L. Stillwell, Jr.

 

 

64,392

 

 

*

 

Jason M. Childress

 

 

41,462

 

 

*

 

Matthew J. Hoss

 

 

10,213

 

 

*

 

All executive officers and directors as a group (9 persons)

 

 

4,143,580

 

 

 

4.90

%

*   Less than 1.0%

 

 

 

 

 

 

 

 

 

(1)

The address for all beneficial owners in this table is 500 Dallas Street, Suite 1600, 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 83,809,509 common units outstanding at January 31, 2017.

Our general partner’s named executive officers also beneficially own derivative securities. See Item 11. “Executive Compensation” for additional information.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table summarizes information about our equity compensation plans as of December 31, 2016:

Plan Category

 

Number of securities to be issued upon exercise of outstanding options, warrants and rights

 

Weighted-average exercise price of outstanding options, warrants and rights

 

Number of securities remaining available for future issuance under equity compensation plans

 

Equity compensation plans not approved by security holders (1):

 

 

 

 

 

 

 

 

Long-Term Incentive Plan

 

 

 

 

194,905

 

 

 

(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.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

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

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.

104


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 IDRs (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

  

Prior to June 1, 2016 we generally made cash distributions 99.9% to our unitholders, pro rata and 0.1% to our general partner, assuming it made any capital contributions necessary to maintain its 0.1% general partner interest in us. In addition, if distributions exceeded the minimum quarterly distribution and other higher target distribution levels, our general partner would have been 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.

 

In connection with the closing of the transactions on June 1, 2016, our partnership agreement was amended and restated to, among other things, (i) convert the 0.1% general partner interest in the Partnership held by MEMP GP into a non-economic general partner interest and (ii) cancel the IDRs.

 

 

 

 

  

Prior to June 1, 2016, our general partner and its affiliates received an aggregate of less than $0.1 million in cash distributions from us.

 

 

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 five months ended May 31, 2016, we reimbursed our general partner and its affiliates an aggregate of $12.3 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.

 

 

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.

Fourth Amended and Restated Limited Liability Company Agreement of Memorial Production Partners GP LLC

Memorial Production Partners GP LLC, our general partner, owns a non-economic general partner interest in us. Under our general partner’s fourth amended and restated limited liability company agreement, the Partnership owns 100% of the membership interests in our general partner.

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.

105


Omnibus Agreement

On June 1, 2016, we terminated the omnibus agreement under which Memorial Resource provided management, administrative and operations personnel to us and our general partner. Pursuant to the omnibus agreement, we were 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 performed services for us or on our behalf. We were also obligated to reimburse Memorial Resource for insurance coverage expenses it incurred 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 had indemnified 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 survives for sixty days after the expiration of the applicable statute of limitations with respect to income taxes.

Pursuant to the omnibus agreement, we indemnified 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 indemnified us for any liability that was incurred as a result of Memorial Resource’s bad faith or willful misconduct in providing operating and administrative services under the omnibus agreement.

Classic Agreements

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.

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 or related person transaction 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 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 or related person transaction 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) any of its affiliates. 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.

Prior to June 1, 2016, Memorial Resource and its affiliates were free to offer properties to us on terms it or they deemed acceptable, and the board of directors of our general partner (or the conflicts committee) was free to accept or reject any such offers, negotiating terms it deemed acceptable to us. As a result, the board of directors of our general partner (or the conflicts committee) would decide, in its sole discretion, the appropriate value of any assets offered to us by Memorial Resource or its affiliates. In so doing, we expected the board of directors (or the conflicts committee) would have considered 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 any of our 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.

106


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.

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, 2016. 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, 2016 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):

 

2016

 

 

2015

 

Audit fees (1)

$

1,185

 

 

$

2,047

 

Audit-related fees (2)

 

25

 

 

 

 

Tax fees (3)

 

 

 

 

 

All other fees (4)

 

 

 

 

 

Total

$

1,210

 

 

$

2,047

 

 

 

(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 2016 and 2015, 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, (iii) services in connection with the Partnership’s acquisitions, and (iv) services in connection with the at-the-market program.

 

(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. For 2016, these fees primarily related to an agreed-upon procedures report in connection with the Partnership’s royalty relief program. No such services were rendered by KPMG during the years ended December 31, 2015.

 

(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, 2016 and 2015.

 

(4)

No such services were rendered by KPMG during the years ended December 31, 2016 and 2015.

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.

 

107


PART IV

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 F-1 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.

ITEM 16.

Form 10-K Summary

None.

108


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: March 10, 2017

By:

 

/s/ Robert L. Stillwell, Jr.

 

 

 

Robert L. Stillwell, Jr.

 

 

 

Vice President and Chief Financial Officer of
Memorial Production Partners GP LLC

 

109


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.

 

Name

 

Title (Position with Memorial Production Partners GP LLC)

 

Date

 

 

 

/s/ William J. Scarff

 

President, Chief Executive Officer and Director

 

March 10, 2017

William J. Scarff

 

(Principal Executive Officer)

 

 

 

 

 

/s/ Robert L. Stillwell, Jr.

 

Vice President and Chief Financial Officer

 

March 10, 2017

Robert L. Stillwell, Jr.

 

(Principal Financial Officer)

 

 

 

 

 

/s/ Matthew J. Hoss

 

Vice President, Accounting

 

March 10, 2017

Matthew J. Hoss

 

(Principal Accounting Officer)

 

 

 

 

 

/s/ Jonathan M. Clarkson

 

Non-Executive Chairman and Director

 

March 10, 2017

Jonathan M. Clarkson

 

 

 

 

 

 

 

/s/ W. Donald Brunson

 

Director

 

March 10, 2017

W. Donald Brunson

 

 

 

 

 

 

 

/s/ P. Michael Highum

 

Director

 

March 10, 2017

P. Michael Highum

 

 

 

 

 

 

 

/s/ John A. Weinzierl

 

Director

 

March 10, 2017

John A. Weinzierl

 

 

 

 

 

 

110


ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

MEMORIAL PRODUCTION PARTNERS LP

INDEX TO FINANCIAL STATEMENTS

 

 

 

Page No.

Report of Independent Registered Public Accounting Firm

 

F-2

Consolidated Balance Sheets as of December 31, 2016 and 2015

 

F-3

Statements of Consolidated and Combined Operations for the Years Ended December 31, 2016, 2015, and 2014

 

F-4

Statements of Consolidated and Combined Cash Flows for the Years Ended December 31, 2016, 2015, and 2014

 

F-5

Statements of Consolidated and Combined Equity for the Years Ended December 31, 2016, 2015, and 2014

 

F-6

Notes to Consolidated and Combined Financial Statements

 

 

Note 1 – Organization and Basis of Presentation

 

F-7

Note 2 – Chapter 11 Proceedings, Ability to Continue as a Going Concern and Covenant Violations

 

F-8

Note 3 – Summary of Significant Accounting Policies

 

F-11

Note 4 – Acquisitions and Divestitures

 

F-17

Note 5 – Fair Value Measurements of Financial Instruments

 

F-20

Note 6 – Risk Management and Derivative Instruments

 

F-22

Note 7 – Asset Retirement Obligations

 

F-24

Note 8 – Restricted Investments

 

F-24

Note 9 – Debt

 

F-25

Note 10 – Equity and Distributions

 

F-30

Note 11 – Earnings per Unit

 

F-34

Note 12 – Equity-based Awards

 

F-34

Note 13 – Related Party Transactions

 

F-36

Note 14 – Commitments and Contingencies

 

F-39

Note 15 – Income Tax

 

F-40

Note 16 – Quarterly Financial Information (Unaudited)

 

F-42

Note 17 – Supplemental Oil and Gas Information (Unaudited)

 

F-42

Note 18- Subsequent Events

 

F-46

 

 

 

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 sheets of Memorial Production Partners LP and subsidiaries (the Partnership) as of December 31, 2016 and 2015, the related consolidated statements of operations, equity, and cash flows for the year ended December 31, 2016, and the related consolidated and combined statements of operations, equity, and cash flows for each of the years in the two-year period ended December 31, 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, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

The accompanying consolidated and combined financial statements have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 2 to the consolidated and combined financial statements, the Partnership’s decreased liquidity has adversely impacted the Partnership’s ability to comply with financial debt covenants and raises substantial doubt about the Partnership’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated and combined financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 1 to the consolidated and combined financial statements, the statements of operations, equity, and cash flows for each of the years in the two-year period ended December 31, 2015 have been prepared on a combined basis of accounting.

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, 2016, 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 March 10, 2017 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

March 10, 2017

 

 

 

F-2


MEMORIAL PRODUCTION PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding units)

 

December 31,

 

 

December 31,

 

 

2016

 

 

2015

 

ASSETS

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

$

15,373

 

 

$

599

 

Accounts receivable

 

34,584

 

 

 

60,239

 

Short-term derivative instruments

 

69,464

 

 

 

272,320

 

Prepaid expenses and other current assets

 

13,163

 

 

 

7,028

 

Total current assets

 

132,584

 

 

 

340,186

 

Property and equipment, at cost:

 

 

 

 

 

 

 

Oil and natural gas properties, successful efforts method

 

3,115,012

 

 

 

3,616,325

 

Support equipment and facilities

 

199,093

 

 

 

205,876

 

Other

 

15,344

 

 

 

2,671

 

Accumulated depreciation, depletion and impairment

 

(1,749,747

)

 

 

(1,878,549

)

Property and equipment, net

 

1,579,702

 

 

 

1,946,323

 

Long-term derivative instruments

 

102,630

 

 

 

461,810

 

Restricted investments

 

156,234

 

 

 

152,631

 

Other long-term assets

 

2,104

 

 

 

5,053

 

Total assets

$

1,973,254

 

 

$

2,906,003

 

 

 

 

 

 

 

 

 

LIABILITIES AND EQUITY

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

Accounts payable

$

4,353

 

 

$

8,792

 

Accounts payable - affiliates

 

 

 

 

3,339

 

Revenues payable

 

21,285

 

 

 

25,504

 

Accrued liabilities (see Note 3)

 

65,235

 

 

 

52,923

 

Short-term derivative instruments

 

 

 

 

2,850

 

Current portion of long-term debt (see Note 9)

 

1,622,904

 

 

 

 

Total current liabilities

 

1,713,777

 

 

 

93,408

 

Long-term debt (see Note 9)

 

 

 

 

2,000,579

 

Asset retirement obligations

 

154,913

 

 

 

162,989

 

Long-term derivative instruments

 

 

 

 

1,441

 

Deferred tax liabilities

 

2,280

 

 

 

2,094

 

Other long-term liabilities

 

2,795

 

 

 

 

Total liabilities

 

1,873,765

 

 

 

2,260,511

 

Commitments and contingencies (see Note 14)

 

 

 

 

 

 

 

Equity:

 

 

 

 

 

 

 

Partners' equity:

 

 

 

 

 

 

 

Common units (83,827,920 units outstanding at December 31, 2016 and 82,906,400 units outstanding at December 31, 2015)

 

99,489

 

 

 

644,644

 

General partner (86,797 units outstanding at December 31, 2015)

 

 

 

 

848

 

Total partners' equity

 

99,489

 

 

 

645,492

 

Total liabilities and equity

$

1,973,254

 

 

$

2,906,003

 

 

See Accompanying Notes to Consolidated and Combined Financial Statements.

 

 

F-3


 

MEMORIAL PRODUCTION PARTNERS LP

STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS

(In thousands, except per unit amounts)

 

 

For the Year Ended

 

 

December 31,

 

 

2016

 

 

2015

 

 

2014

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

Oil & natural gas sales

$

284,051

 

 

$

355,422

 

 

$

561,677

 

Other revenues

 

529

 

 

 

2,725

 

 

 

4,366

 

Total revenues

 

284,580

 

 

 

358,147

 

 

 

566,043

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

126,175

 

 

 

168,199

 

 

 

143,733

 

Gathering, processing, and transportation

 

34,979

 

 

 

34,939

 

 

 

31,892

 

Exploration

 

981

 

 

 

2,317

 

 

 

2,750

 

Taxes other than income

 

15,540

 

 

 

25,828

 

 

 

33,141

 

Depreciation, depletion, and amortization

 

171,629

 

 

 

195,814

 

 

 

185,955

 

Impairment of proved oil and natural gas properties

 

183,437

 

 

 

616,784

 

 

 

407,540

 

General and administrative

 

63,280

 

 

 

56,671

 

 

 

49,124

 

Accretion of asset retirement obligations

 

10,231

 

 

 

7,125

 

 

 

5,773

 

(Gain) loss on commodity derivative instruments

 

117,105

 

 

 

(462,890

)

 

 

(492,254

)

(Gain) loss on sale of properties

 

(2,754

)

 

 

(2,998

)

 

 

 

Other, net

 

516

 

 

 

(665

)

 

 

(11

)

Total costs and expenses

 

721,119

 

 

 

641,124

 

 

 

367,643

 

Operating income (loss)

 

(436,539

)

 

 

(282,977

)

 

 

198,400

 

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net

 

(146,031

)

 

 

(115,154

)

 

 

(83,550

)

Other income (expense)

 

8

 

 

 

43

 

 

 

(657

)

Gain on extinguishment of debt

 

42,337

 

 

 

422

 

 

 

 

Total other income (expense)

 

(103,686

)

 

 

(114,689

)

 

 

(84,207

)

Income (loss) before income taxes

 

(540,225

)

 

 

(397,666

)

 

 

114,193

 

Income tax benefit (expense)

 

(173

)

 

 

2,175

 

 

 

1,421

 

Net income (loss)

 

(540,398

)

 

 

(395,491

)

 

 

115,614

 

Net income (loss) attributable to noncontrolling interest

 

 

 

 

386

 

 

 

32

 

Net income (loss) attributable to Memorial Production Partners LP

$

(540,398

)

 

$

(395,877

)

 

$

115,582

 

 

 

 

 

 

 

 

 

 

 

 

 

Limited partners' interest in net income (loss):

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to Memorial Production Partners LP

$

(540,398

)

 

$

(395,877

)

 

$

115,582

 

Net (income) loss allocated to previous owners

 

 

 

 

2,268

 

 

 

2,465

 

Net (income) loss allocated to general partner

 

168

 

 

 

327

 

 

 

(206

)

Net (income) loss allocated to NGP IDRs

 

 

 

 

(83

)

 

 

(88

)

Limited partners' interest in net income (loss)

$

(540,230

)

 

$

(393,365

)

 

$

117,753

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings per unit: (Note 11)

 

 

 

 

 

 

 

 

 

 

 

Basic and diluted earnings per unit

$

(6.48

)

 

$

(4.71

)

 

$

1.66

 

Weighted average limited partner units outstanding:

 

 

 

 

 

 

 

 

 

 

 

Basic and diluted

 

83,351

 

 

 

83,528

 

 

 

70,859

 

 

See Accompanying Notes to Consolidated and Combined Financial Statements.

F-4


 

MEMORIAL PRODUCTION PARTNERS LP

STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS

(In thousands)

 

 

For the Year Ended

 

 

December 31,

 

 

2016

 

 

2015

 

 

2014

 

Cash flows from operating activities:

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

$

(540,398

)

 

$

(395,491

)

 

$

115,614

 

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion, and amortization

 

171,629

 

 

 

195,814

 

 

 

185,955

 

Impairment of proved oil and natural gas properties

 

183,437

 

 

 

616,784

 

 

 

407,540

 

(Gain) loss on derivative instruments

 

118,395

 

 

 

(458,216

)

 

 

(492,405

)

Cash settlements (paid) received on expired derivative instruments

 

210,704

 

 

 

250,043

 

 

 

11,693

 

Cash settlements (paid) on terminated derivatives

 

228,646

 

 

 

47,930

 

 

 

 

Premiums paid for commodity derivatives

 

 

 

 

(47,930

)

 

 

 

Bad debt expense

 

2,050

 

 

 

 

 

 

 

Deferred income tax expense (benefit)

 

187

 

 

 

(2,234

)

 

 

(1,548

)

Amortization and write-off of deferred financing costs

 

22,106

 

 

 

6,058

 

 

 

4,227

 

Amortization and write-off of senior notes discount

 

13,185

 

 

 

2,430

 

 

 

1,921

 

Gain on extinguishment of debt

 

(42,337

)

 

 

(422

)

 

 

 

Accretion of asset retirement obligations

 

10,231

 

 

 

7,125

 

 

 

5,773

 

Gain on sale of properties

 

(2,754

)

 

 

(2,998

)

 

 

 

Unit-based compensation (see Note 12)

 

7,350

 

 

 

10,809

 

 

 

7,874

 

Settlement of asset retirement obligations

 

(1,442

)

 

 

(1,430

)

 

 

 

Exploration costs

 

792

 

 

 

2,078

 

 

 

1,960

 

Other

 

229

 

 

 

 

 

 

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

Accounts receivable

 

23,928

 

 

 

15,528

 

 

 

(18,022

)

Prepaid expenses and other assets

 

(4,088

)

 

 

2,275

 

 

 

(2,695

)

Payables and accrued liabilities

 

4,084

 

 

 

(32,068

)

 

 

27,037

 

Other

 

2,692

 

 

 

666

 

 

 

(651

)

Net cash provided by operating activities

 

408,626

 

 

 

216,751

 

 

 

254,273

 

Cash flows from investing activities:

 

 

 

 

 

 

 

 

 

 

 

Acquisitions of oil and natural gas properties

 

 

 

 

(100,730

)

 

 

(1,083,761

)

Acquisition post-closing adjustments receipts

 

 

 

 

9,570

 

 

 

 

Additions to oil and gas properties

 

(57,675

)

 

 

(241,299

)

 

 

(298,274

)

Additions to restricted investments

 

(8,443

)

 

 

(5,690

)

 

 

(3,976

)

Withdrawals of restricted investments

 

4,840

 

 

 

 

 

 

 

Additions to other property and equipment

 

(7,875

)

 

 

 

 

 

(98

)

Proceeds from the sale of oil and natural gas properties, net of cash and cash equivalents sold

 

52,711

 

 

 

580

 

 

 

 

Net cash used in investing activities

 

(16,442

)

 

 

(337,569

)

 

 

(1,386,109

)

Cash flows from financing activities:

 

 

 

 

 

 

 

 

 

 

 

Advances on revolving credit facilities

 

144,000

 

 

 

562,000

 

 

 

1,446,000

 

Payments on revolving credit facilities

 

(468,348

)

 

 

(138,000

)

 

 

(1,137,000

)

Proceeds from senior notes

 

 

 

 

 

 

 

492,425

 

Deferred financing costs

 

(1,350

)

 

 

(341

)

 

 

(11,494

)

Repurchase of senior notes

 

(41,261

)

 

 

(2,914

)

 

 

 

Capital contributions from previous owners

 

 

 

 

1,912

 

 

 

5,990

 

Contributions related to sale of assets to NGP affiliate

 

26

 

 

 

860

 

 

 

 

Transfer of operating subsidiary from Memorial Resource

 

2,363

 

 

 

 

 

 

 

Proceeds from general partner contributions

 

 

 

 

 

 

 

570

 

Proceeds from the issuance of common units

 

2,385

 

 

 

 

 

 

553,288

 

Costs incurred in conjunction with issuance of common units

 

(536

)

 

 

 

 

 

(12,510

)

Purchase of noncontrolling interest

 

 

 

 

(5,946

)

 

 

 

Distributions to partners

 

(13,300

)

 

 

(163,259

)

 

 

(154,852

)

Distribution to Memorial Resource (see Note 1)

 

 

 

 

(78,396

)

 

 

(48,880

)

Acquisition of General Partner (see Note 1)

 

(750

)

 

 

 

 

 

 

Acquisition of IDRs from NGP (see Note 1)

 

(50

)

 

 

 

 

 

 

Restricted units returned to plan

 

(589

)

 

 

(1,285

)

 

 

(1,012

)

Repurchases under unit repurchase program

 

 

 

 

(54,184

)

 

 

(11,531

)

Distributions made by previous owners

 

 

 

 

 

 

 

(9,886

)

Net cash (used in) provided by financing activities

 

(377,410

)

 

 

120,447

 

 

 

1,111,108

 

Net change in cash and cash equivalents

 

14,774

 

 

 

(371

)

 

 

(20,728

)

Cash and cash equivalents, beginning of period

 

599

 

 

 

970

 

 

 

21,698

 

Cash and cash equivalents, end of period

$

15,373

 

 

$

599

 

 

$

970

 

 

See Accompanying Notes to Consolidated and Combined Financial Statements.

See Note 3 for Supplemental Cash Flow information

 

F-5


 

MEMORIAL PRODUCTION PARTNERS LP

STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY

(In thousands)

 

 

Partner's Equity (Deficit)

 

 

 

 

 

 

 

 

 

 

Limited Partners

 

 

General

 

 

Previous

 

 

NGP

 

 

Noncontrolling

 

 

 

 

 

 

Common

 

 

Subordinated

 

 

Partner

 

 

Owners

 

 

IDRs

 

 

Interest

 

 

Total

 

Balance, December 31, 2013

$

582,075

 

 

$

(8,715

)

 

$

728

 

 

$

283,405

 

 

$

 

 

$

5,528

 

 

$

863,021

 

Net income (loss)

 

113,573

 

 

 

4,180

 

 

 

206

 

 

 

(2,465

)

 

 

88

 

 

 

32

 

 

 

115,614

 

Net proceeds from the issuance of common units

 

540,698

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

540,698

 

Contributions

 

 

 

 

 

 

 

570

 

 

 

5,990

 

 

 

 

 

 

 

 

 

6,560

 

Distributions

 

(142,719

)

 

 

(11,794

)

 

 

(251

)

 

 

(9,886

)

 

 

(88

)

 

 

 

 

 

(164,738

)

Distribution attributable to net assets acquired (see Note 13)

 

(2,321

)

 

 

(90

)

 

 

(2

)

 

 

 

 

 

 

 

 

 

 

 

(2,413

)

Distribution of net asset to MRD Holdco

 

 

 

 

 

 

 

 

 

 

(26,131

)

 

 

 

 

 

 

 

 

(26,131

)

Amortization of equity awards

 

7,874

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

7,874

 

Tax related effects attributable to Memorial Resource restructuring and initial public offering

 

 

 

 

 

 

 

 

 

 

(30,483

)

 

 

 

 

 

 

 

 

(30,483

)

Common units repurchased under repurchase program (see Note 10)

 

(12,903

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(12,903

)

Restricted units repurchased (see Note 10)

 

(1,012

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1,012

)

Other

 

 

 

 

 

 

 

 

 

 

227

 

 

 

 

 

 

 

 

 

227

 

Balance, December 31, 2014

 

1,085,265

 

 

 

(16,419

)

 

 

1,251

 

 

 

220,657

 

 

 

 

 

 

5,560

 

 

 

1,296,314

 

Net income (loss)

 

(393,395

)

 

 

30

 

 

 

(327

)

 

 

(2,268

)

 

 

83

 

 

 

386

 

 

 

(395,491

)

Contributions (see Note 13)

 

2,962

 

 

 

 

 

 

3

 

 

 

1,912

 

 

 

 

 

 

 

 

 

4,877

 

Distributions

 

(159,975

)

 

 

(2,949

)

 

 

(252

)

 

 

 

 

 

(83

)

 

 

 

 

 

(163,259

)

Distribution attributable to net assets transferred (see Note 1)

 

(78,318

)

 

 

 

 

 

(78

)

 

 

 

 

 

 

 

 

 

 

 

(78,396

)

Net book value of net assets exchanged (see Note 1)

 

250,791

 

 

 

 

 

 

251

 

 

 

(248,321

)

 

 

 

 

 

 

 

 

2,721

 

Purchase of noncontrolling interest

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(5,946

)

 

 

(5,946

)

Amortization of equity awards

 

10,809

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

10,809

 

Conversion of subordinated units to common units

 

(19,338

)

 

 

19,338

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common units repurchased under repurchase program (see Note 10)

 

(52,813

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(52,813

)

Restricted units repurchased and other

 

(1,344

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1,344

)

Deferred tax liability retained by previous owner (see Note 3)

 

 

 

 

 

 

 

 

 

 

28,020

 

 

 

 

 

 

 

 

 

28,020

 

Balance, December 31, 2015

 

644,644

 

 

 

 

 

 

848

 

 

 

 

 

 

 

 

 

 

 

 

645,492

 

Net income (loss)

 

(540,230

)

 

 

 

 

 

(168

)

 

 

 

 

 

 

 

 

 

 

 

(540,398

)

Distributions

 

(13,289

)

 

 

 

 

 

(11

)

 

 

 

 

 

 

 

 

 

 

 

(13,300

)

Purchase of equity interest of general partner (see Note 1)

 

(81

)

 

 

 

 

 

(669

)

 

 

 

 

 

 

 

 

 

 

 

(750

)

Acquisition of IDRs from NGP (see Note 1)

 

(50

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(50

)

Net proceeds from issuance of common units

 

1,849

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1,849

 

Amortization of unit-based awards

 

7,206

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

7,206

 

Restricted units repurchased and other

 

(560

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(560

)

Balance at December 31, 2016

$

99,489

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

99,489

 

 

See Accompanying Notes to Consolidated and Combined Financial Statements.

 

 

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.” See Note 2 for additional information regarding the Notice of Delisting. 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, 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” and “MEMP GP” refers to Memorial Production Partners GP LLC, our general partner and wholly-owned subsidiary; (ii) “Memorial Resource” refers to Memorial Resource Development Corp., the former owner of our general partner; (iii) “MRD LLC” refers to Memorial Resource Development LLC, which is the predecessor of Memorial Resource; (iv) “the Funds” refers collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively control MRD Holdco; (v) “OLLC” refers to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties; (vi) “Finance Corp.” refers 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” refers to MRD Holdco LLC, which together with a group controlled Memorial Resource and  (viii) “NGP” refer to Natural Gas Partners.

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

In connection with the closing of the transactions on June 1, 2016, our partnership agreement was amended and restated to, among other things, (i) convert the 0.1% general partner interest in the Partnership held by MEMP GP into a non-economic general partner interest, (ii) cancel the IDRs, and (iii) provide that the limited partners of the Partnership will elect the members of MEMP GP’s board of directors beginning with our next annual meeting. In addition, we terminated the omnibus agreement under which Memorial Resource provided management, administrative and operations personnel to us and our general partner, and we entered into a transition services agreement with Memorial Resource to manage certain post-closing separation costs and activities. See Note 13 for additional information regarding the MEMP GP Acquisition and the transition services agreement.

Previous Owners

References to “the previous owners” for accounting and financial reporting purposes refer collectively to certain oil and natural gas properties primarily located in East Texas and 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”).

The 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 periods after common control commenced through the acquisition date. See Note 13 for additional information.

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.

F-7


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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 located offshore Southern California (the “Beta properties”) from a third party for approximately $94.6 million (the “2015 Beta Acquisition”). See Note 4 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. Gain on extinguishment of debt were previously accounted for as interest expense, net and are now being presented as other income (expenses) on our statements of operations on a separate line item.

Note 2. Chapter 11 Proceedings, Ability to Continue as a Going Concern and Covenant Violations

Throughout 2016, the Partnership along with its legal and financial advisors, explored strategic alternatives with a focus on liquidity and financial flexibility. The Partnership specifically evaluated options with the lenders under our revolving credit facility and holders of the Partnership’s senior notes that would improve liquidity and deleverage the Partnership. During this process, we elected to defer an approximately $24.6 million interest payment due on November 1, 2016 with respect to the 7.625% senior notes due May 2021 (“2021 Senior Notes”). The interest payment was subject to a 30-day grace period under the indenture. Failure to pay such interest payment on November 1, 2016 would have resulted in certain defaults and events of default under our revolving credit facility. The lenders under the revolving credit facility, on November 1, 2016, waived such defaults and event of default through November 30, 2016 (such period from November 1, 2016 to November 30, 2016, the “Waiver Period”), in each case, subject to the terms and conditions set forth in the limited waiver and twelfth amendment (the “Waiver and Twelfth Amendment”) to our revolving credit facility.

On November 30, 2016, the Partnership, OLLC, certain subsidiaries of the Partnership, the administrative agent, and the lenders consenting thereto entered into the first amendment to the limited waiver under our revolving credit facility, extending the Waiver Period to December 16, 2016.

On November 30, 2016, the Partnership entered into a forbearance agreement with certain noteholders that held approximately 51.7% of the Partnership’s 2021 Senior Notes and 69% of the Partnership’s 6.875% senior notes due August 2022 (“2022 Senior Notes”). Under the forbearance agreement the noteholders agreed to forbear from exercising any and all remedies available to them as a result of the Partnership’s election not to make an interest payment of $24.6 million due on the 2021 Senior Notes. The forbearance agreements initially extended through December 7, 2016 and were subsequently extended through December 16, 2016.

On December 16, 2016, the Partnership, OLLC, certain subsidiaries of the Partnership, the administrative agent, and the lenders consenting thereto entered into the second amendment to limited waiver under its revolving credit facility, extending the Waiver Period to January 13, 2017. In addition, the forbearance agreements were extended through January 13, 2017.

On December 22, 2016, the Partnership entered into a Plan Support Agreement (the “Noteholder PSA”) with holders of over an aggregate of 50.2% of the aggregate outstanding principal amount of the 2021 Senior Notes and the 2022 Senior Notes (collectively, the “Notes”), as well as reached an agreement-in-principle with the administrative agent under our revolving credit facility on the terms of a financial restructuring. Under the terms of the Noteholder PSA, the financial restructuring would be effected through a prepackaged or prenegotiated plan of reorganization (the “Plan”). Pursuant to the terms of the Plan, which would be subject to approval of the Bankruptcy Court, it is anticipated that, among other things, on the effective date of the Plan (the “Effective Date”):

 

A newly formed corporation, as successor to the Partnership (“Reorganized Memorial”) would issue (i) new common shares (the “New Common Shares”) and (ii)  five year warrants (the “Warrants”) entitling their holders upon exercise thereof, on a pro rata basis, to 8% of the total issued and outstanding New Common Shares, at a per share exercise price equal to the principal and accrued interest on the Senior Notes as of December 31, 2016, divided by the number of issued and outstanding New Common Shares (including New Common Shares issuable upon exercise of the Warrants), which New Common Shares and Warrants will be distributed as set forth below;

 

The Notes would be cancelled and discharged and the holders of those Notes would receive (directly or indirectly) New Common Shares representing, in the aggregate, 98% of the New Common Shares issued on the Effective Date (subject to dilution by the post-emergence management incentive plan and the New Common Shares issuable upon exercise of the Warrants);

F-8


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

 

The noteholders, at their election, would be entitled to receive an additional cash payment of up to approximately $24.6 million;

 

Each holder of existing equity interests in the Partnership would receive its pro rata share of (i) New Common Shares representing, in the aggregate, 2% of the New Common Shares issued on the Effective Date and (ii) the Warrants (in each case, subject to dilution by the post-emergence management incentive plan and, in the case of the New Common Shares, subject to dilution by the Warrants);

 

General unsecured claims, on or after the effective date, would be paid in the ordinary course; and

 

Reorganized Memorial would enter into an exit credit facility in the form of an amendment and restatement of the existing revolving credit facility (the “Exit Credit Facility”).

The Partnership expects to emerge from the Chapter 11 proceedings as a corporation, including for U.S. federal income tax purposes.

On January 13, 2017, the Partnership entered into the third amendment to limited waiver, which extended the outside date of the Waiver Period from January 13, 2017 to January 16, 2017. In addition, the Partnership entered into a Plan Support Agreement (the “RBL PSA”) with lenders holding 100% of the loans under our revolving credit facility. The RBL PSA was entered into on terms substantially similar to those of the Noteholder PSA. In addition, among other things, the RBL PSA provided that (i) the consenting lenders (as defined in the RBL PSA) may terminate the RBL PSA upon the termination of the Noteholder PSA or if there is an amendment to the Noteholder PSA that is, or would reasonably be expected to be, adverse to the administrative agent under our revolving credit facility or the consenting lenders and (ii) each of the Debtors agreed to not file a voluntary petition for relief under Chapter 11 of title 11 of the United States Code (“Bankruptcy Code”) until the Debtors terminated certain swap agreements identified in the RBL PSA and used the net proceeds thereof to repay outstanding amounts under the revolving credit facility.  

An indicative summary of the expected terms and conditions of the Exit Credit Facility is set forth in an annex to the RBL PSA filed with our Current Report on Form 8-K filed with the SEC on January 17, 2017, which terms and conditions may include (but are not limited to) the following:

 

senior secured revolving credit facility with maximum aggregate commitments of $1 billion, subject to a borrowing base;

 

an expected initial borrowing base of approximately $474.0 to $492.5 million based on a April emergence date to be effective upon consummation of the restructuring transactions, subject to an amortization schedule thereafter until November 1, 2017;

 

the first scheduled borrowing base redetermination will occur on November 1, 2017 and thereafter, each April 1st and October 1st;

 

a maturity date of March 19, 2021;

 

an ongoing covenant requiring that we grant a security interest in substantially all of our personal and real property that we mortgage, in each case as collateral for the obligations under the Exit Credit Facility, oil and gas properties representing not less than 95% of the total value of our oil and gas properties evaluated in the most recently completed reserve report;

 

the loans under the Exit Credit Facility shall bear interest at a rate per annum equal to the base rate or LIBOR/Eurodollar rate plus an applicable margin that ranges from 2.00% to 3.00% per annum (based on borrowing base usage) on alternate base rate loans and from 3.00% to 4.00% per annum (based on borrowing base usage) on LIBOR/Eurodollar loans;

 

the loan commitments under the Exit Credit Facility are subject to a commitment fee on the unused portion of the borrowing base at a rate per annum equal to 0.50%;

 

customary mandatory prepayments as well as a requirement that, in the event that as of the close of any business day the aggregate amount of our unrestricted cash and cash equivalents exceeds $35.0 million in the aggregate, we must prepay the loans under the Exit Credit Facility (without a corresponding reduction in the available commitments under the Exit Credit Facility) and cash-collateralize any letter of credit exposure in an amount equal to such excess; provided that, we may elect to increase such the excess cash threshold from $35.0 million to $50.0 million at such time as the aggregate amount of net cash proceeds received from asset sales exceeds the borrowing base value attributable to such assets (if any) equals or exceeds $15.0 million; provided further, however, that in the event that we issue certain unsecured debt in an aggregate amount of $10.0 million or greater, we will no longer have the ability to increase such threshold above $35.0 million and, if such threshold is greater than $35.0 million at such time, such threshold will be immediately reduced to $35.0 million;

F-9


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

 

financial covenants, requiring that we maintain a ratio of (i) consolidated EBITDAX (to be defined in the Exit Credit Facility) for the four fiscal quarter period then ending to consolidated net interest expense for such period of not less than 2.50 to 1.00, which we refer to as the interest coverage ratio, (ii) consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0; and (iii) consolidated total debt as of such time to consolidated EBITDAX for the four fiscal quarter period then ending on such day of not greater than 4.0 to 1.0;

 

a requirement that we hedge no less than 50% of our forecasted proved developed producing production through 2019 on or prior to December 31, 2017; and

 

representation and warranties, affirmative covenants, negative covenants, events of default and other restrictive provisions substantially consistent with our current revolving credit facility, subject to certain exceptions and a provision permitting us, under specified and limited circumstances, to incur additional unsecured indebtedness in an original aggregate principal amount not to exceed $80.0 million.

On January 16, 2017, the Partnership and certain of its subsidiaries (collectively with the Partnership, the “Debtors”) filed voluntary petitions (the cases commenced thereby, the “Chapter 11 proceedings”) under the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”) to pursue a Joint Chapter 11 Plan of Reorganization for the Debtors. The Debtors’ Chapter 11 proceedings are being jointly administered under the caption In re Memorial Production Partners LP, et al. (Case No. 17-30262). The Bankruptcy Court has granted all of the first day motions filed by the Debtors that were designed primarily to minimize the impact of the Chapter 11 proceedings on the Partnership’s operations, customers and employees. The Debtors will continue to operate their businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The Partnership expects to continue its operations without interruption during the pendency of the Chapter 11 proceedings.

For the duration of the Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to risks and uncertainties associated with Chapter 11 proceedings described in Item 1A, “Risk Factors.” As a result of these risks and uncertainties, our assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this annual report may not accurately reflect our operations, properties and capital plans following the Chapter 11 proceedings.

Ability to Continue as a Going Concern

Continued low commodity prices have resulted in significantly lower levels of cash flow from operating activities and have limited the Partnership’s ability to access the capital markets. In addition, 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. Continued low commodity prices have adversely impacted our redeterminations. During the second semi-annual redetermination in October, the lenders under our revolving credit facility decreased our borrowing base from $925.0 million to $740.0 million with a further reduction to $720.0 million in December 2016. The borrowing base was further reduced in December 2016 to $530.7 million due to the monetization of certain derivative instruments, as discussed in Note 6. The reduced borrowing base has had a significant negative impact on the Partnership’s liquidity and ability to remain in compliance with certain financial covenants. On January 16, 2017, the Debtors’ Chapter 11 proceedings accelerated the Partnership’s obligations under its revolving credit facility, 2021 Senior Notes and 2022 Senior Notes.

The significant risks and uncertainties related to the Partnership’s liquidity and Chapter 11 proceedings described above raise substantial doubt about the Partnership’s ability to continue as a going concern. The condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If the Partnership cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material.

In order to decrease the Partnership’s level of indebtedness and maintain the Partnership’s liquidity at levels sufficient to meet its commitments, the Partnership undertook a number of actions, including divesting certain non-core assets, minimizing capital expenditures and further reducing its recurring operating expenses. Despite taking these actions, the Partnership did not have sufficient liquidity to satisfy its debt service obligations, meet other financial obligations and comply with its debt covenants. As a result, the Debtors filed bankruptcy petitions under Chapter 11 of the Bankruptcy Code.

F-10


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Notice of Delisting

On January 17, 2017, the Partnership received a letter from the Listing Qualifications Department of The NASDAQ Stock Market LLC (“NASDAQ”) notifying the Partnership that (1) as a result of the Chapter 11 proceedings, and in accordance with NASDAQ Listing Rules 5101, 5110(b) and IM-5101-1, NASDAQ had determined that the Partnership’s common units would be delisted from NASDAQ and (2) accordingly, unless the Partnership requested an appeal of this determination, trading of the common units would have been suspended at the opening of business on January 26, 2017 and the Partnership’s securities would have been removed from listing and registration on NASDAQ. The Partnership has appealed this determination.

Note 3. 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.

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 subsidiary in which we have a controlling interest and acquired the remaining interests on November 3, 2015, after the elimination of all intercompany accounts and transactions. Likewise, the combined financial statements include the accounts of the previous owners as discussed above in Note 1. 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 which are 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.

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. 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. At December 31, 2016, we recorded $1.9 million as an allowance for doubtful accounts. Management determined that an allowance for uncollectible accounts was unnecessary at December 31, 2015.

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.

F-11


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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 has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs attributable to unproved locations 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, 2016, 2015 and 2014.

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, 2016.

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, office build-out cost and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to seven years.

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 8 for additional information.

Debt Issuance Costs

These costs were historically 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. The remaining unamortized debt issuance cost was written off at December 31, 2016, due to (i) the uncertainty regarding the Partnership’s ability to cure the default discussed above in Note 2, (ii) our inability to comply with certain financial covenants contained in our revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2016, 2015 and 2014 was approximately $22.1 million, $6.1 million, and $4.2 million, respectively.

F-12


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 and probable 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, 2016, 2015 and 2014 was approximately $183.4 million, $616.8 million, and $407.5  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 7 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, 2016 or 2015.

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

 

 

For the Year Ending December 31,

 

 

2016

 

 

2015

 

 

2014

 

Major customers:

 

 

 

 

 

 

 

 

 

 

 

Phillips 66

 

19%

 

 

 

12%

 

 

 

12%

 

Sinclair Oil & Gas Company

 

16%

 

 

 

18%

 

 

 

11%

 

Royal Dutch Shell plc and subsidiaries

 

14%

 

 

 

14%

 

 

n/a

 

 

General and Administrative Expense

Prior to June 1, 2016, Memorial Resource provided management, administrative and operating services to the Partnership and our general partner pursuant to our omnibus agreement. Upon completion of the MEMP GP Acquisition, the omnibus agreement was terminated on June 1, 2016, and the Partnership entered into a transition services agreement with Memorial Resource to manage certain post-closing separation costs and activities. Prior to the MEMP GP Acquisition, our partnership agreement provided that our general partner determined in good faith the expenses that are allocated to us, including expenses incurred by our general partner and its former affiliates on our behalf. Memorial Resource allocated indirect general and administrative costs based on time allocations for the three months ended March 31, 2016 and the years ended December 31, 2015 and 2014 and based on the terms as set forth by the MEMP GP Acquisition purchase and sale agreement for the period from April 1, 2016 through the closing date. Under our partnership agreement and the omnibus agreement, we reimbursed Memorial Resource for all direct and indirect costs incurred on our behalf. See Note 13 for additional information regarding the omnibus agreement.

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.

F-13


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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, 2016, 2015 and 2014, we had $0.5 million, $2.1 million and $2.8 million in capitalized interest, respectively.

Income Tax

We are currently 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 basis 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 11 for additional information.

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 12 for further information.

F-14


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Accrued Liabilities

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

 

 

December 31,

 

 

December 31,

 

 

2016

 

 

2015

 

Accrued interest payable

$

46,417

 

 

$

23,192

 

Accrued lease operating expense

 

10,411

 

 

 

16,843

 

Accrued capital expenditures

 

1,826

 

 

 

8,110

 

Accrued general and administrative expenses

 

3,040

 

 

 

1,961

 

Accrued ad valorem tax

 

977

 

 

 

1,426

 

Asset retirement obligation

 

789

 

 

 

1,175

 

Environmental liability

 

 

 

 

216

 

Other

 

1,775

 

 

 

 

 

$

65,235

 

 

$

52,923

 

 

Supplemental Cash Flows

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

 

For the Year Ended

 

 

December 31,

 

 

2016

 

 

2015

 

 

2014

 

Supplemental cash flows:

 

 

 

 

 

 

 

 

 

 

 

Cash paid for interest, net of amounts capitalized

$

87,527

 

 

$

107,272

 

 

$

63,709

 

Cash paid for taxes

 

 

 

 

472

 

 

 

151

 

Noncash investing and financing activities:

 

 

 

 

 

 

 

 

 

 

 

Increase (decrease) in capital expenditures in payables and accrued liabilities

 

(6,284

)

 

 

(27,932

)

 

 

13,759

 

(Increase) decrease in accounts receivable related to acquisitions

 

 

 

 

9,698

 

 

 

(5,854

)

(Increase) decrease in accounts receivable/payable related to divestitures

 

(289

)

 

 

 

 

 

 

Repurchases under unit repurchase program

 

 

 

 

 

 

 

1,372

 

Assumptions of asset retirement obligations related to acquisitions

 

 

 

 

23,754

 

 

 

4,265

 

Asset retirement obligation removal related to divestitures

 

(19,669

)

 

 

 

 

 

 

 

New Accounting Pronouncements

Statement of Cash Flows – Restricted Cash a consensus of the FASB Emerging Issues Task Force. In November 2016, the FASB issued an accounting standards update to clarify the guidance on the classification and presentation of restricted cash in the statement of cash flows. The changes in restricted cash and restricted cash equivalents that result from the transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows.  The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The new guidance requires transition under a retrospective approach for each period presented. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures.

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

F-15


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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

For the amendments that change the recognition and measurement of share-based payment awards, the new guidance requires transition under a modified retrospective approach, with a cumulative-effect adjustment made to retained earnings as of the beginning of the fiscal period in which the guidance is adopted. Prospective application is required for the accounting for excess tax benefits and tax deficiencies. The Partnership adopted this guidance as of January 1, 2017, and it will not have a material impact on the Partnership’s future consolidated financial statements.

Leases. In February 2016, the FASB issued a revision to lease accounting guidance. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term.

The Partnership is the lessee under various agreements for office space, compressors, equipment, and surface rentals that are currently accounted for as operating leases, refer to Note 14, Commitments and Contingencies. As a result, these new rules will increase reported assets and liabilities. The Partnership will not early adopt this standard. The Partnership will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019 using a modified retrospective approach, including several optional practical expedients related to leases commenced before the effective date. The Partnership is currently evaluating the impact of these rules on its financial statements and has started the assessment process by evaluating the population of leases under the revised definition. The adoption of this standard will result in an increase in the assets and liabilities on the Partnership’s consolidated balance sheets. The quantitative impacts of the new standard are dependent on the leases in force at the time of adoption. As a result, the evaluation of the effect of the new standards will extend over future periods.

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

F-16


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Revenue from Contracts with Customers. In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance, requires enhanced disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The guidance is effective for interim and annual reporting periods starting January 1, 2018, and early adoption is permitted. The Partnership will not early adopt the standard, and plans to use a modified retrospective approach upon adoption, with the cumulative effect of initial application recognized at the date of initial application subject to certain additional disclosures. The Partnership has started the assessment process by evaluating its revenue streams and evaluating contracts under the revised standards. The Partnership is currently evaluating the standard and the impact it is expected to have on the consolidated financial statements and related footnote disclosures.

Presentation of Financial Statements — Going Concern: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. In August 2014, the FASB issued an accounting standards update that requires management to perform interim and annual assessments of whether there are conditions or events that raise substantial doubt of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. Certain disclosures are required if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The guidance is effective for annual periods ending after December 15, 2016, and interim periods thereafter, and with early adoption permitted. The amendments will not impact our financial position or results of operations but will require management to perform a formal going concern assessment. The Partnership adopted this guidance and has applied this guidance in its consolidated financial statements and related footnote disclosures. See Note 2 for additional information.

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 4. Acquisitions and Divestitures

The third party acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, we 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 our revolving credit facility.

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 13, directly or indirectly from Memorial Resource and certain affiliates of NGP.

Acquisition and Divestiture related expenses

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

 

For the Year Ended

 

December 31,

 

2016

 

 

2015

 

 

2014

 

$

1,451

 

 

$

1,928

 

 

$

4,363

 

F-17


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

 

2015 Acquisitions

2015 Beta Acquisition. On November 3, 2015, we closed the 2015 Beta Acquisition, which included the acquisition of the noncontrolling interest in SPBPC for approximately $6.0 million and the acquisition of the remaining interests in our oil and gas properties located offshore Southern California from a third party for approximately $94.6 million. 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):

 

 

2015 Beta

 

 

Acquisition

 

Oil and gas properties

$

40,029

 

Prepaid expenses and other current assets

 

840

 

Restricted investments

 

69,579

 

Derivative instruments

 

4,568

 

Accounts receivable - affiliates and other

 

4,499

 

Asset retirement obligations

 

(22,871

)

Accrued liabilities

 

(2,010

)

Total identifiable net assets

$

94,634

 

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.

 

 

For the Year Ended

 

 

December 31,

 

 

2015

 

 

2014

 

 

(In thousands, except per unit amounts)

 

Revenues

$

381,495

 

 

$

613,563

 

Net income (loss)

 

(394,756

)

 

 

132,630

 

Basic and diluted earnings per unit

 

(4.73

)

 

 

1.87

 

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):

 

 

Wyoming

 

 

Acquisition

 

Oil and gas properties

$

930,168

 

Asset retirement obligations

 

(3,980

)

Revenues payable

 

(375

)

Accrued liabilities

 

(19,693

)

Total identifiable net assets

$

906,120

 

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.

F-18


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):

 

 

Eagle Ford

 

 

Acquisition

 

Oil and gas properties

$

168,606

 

Asset retirement obligations

 

(285

)

Accrued liabilities

 

(250

)

Total identifiable net assets

$

168,071

 

 

The following unaudited pro forma combined results of operations is provided for the year ended December 31, 2014 as though the Eagle Ford Acquisition and Wyoming 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 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.

 

For the Year Ended

 

 

December 31,

 

 

2014

 

 

(In thousands, except per unit amounts)

 

Revenues

$

666,508

 

Net income (loss)

 

153,843

 

Basic and diluted earnings per unit

 

2.20

 

 

2016 Divestitures

On July 14, 2016, we closed a transaction to divest certain assets located in Colorado and Wyoming (the “Rockies Divestiture”) to a third party for total proceeds of approximately $16.4 million, including final post-closing adjustments. We recorded a loss of approximately $4.2 million in “(gain) loss on sale of properties” in the accompanying statement of operations. The proceeds from this transaction were used to reduce borrowings under our revolving credit facility. This disposition does not qualify as a discontinued operation.

On June 14, 2016, we closed a transaction to divest certain assets located in the Permian Basin (the “Permian Divestiture”) to a third party for a total purchase price of approximately $36.7 million including estimated post-closing adjustments, which included $36.4 million in cash and $0.3 million in accounts receivable at December 31, 2016. We recognized a gain of $6.1 million on the sale of properties related to the Permian Divestiture in “(gain) loss on sale of properties” in the accompanying statement of operations. The proceeds from this transaction were used to reduce borrowings under our revolving credit facility. This disposition does not qualify as a discontinued operation.

During the year ended December 31, 2016, the Partnership completed other immaterial divestitures for less than $0.1 million for which we recorded a gain of $0.9 million on the sale that is recorded in “(gain) loss on sale of properties” in the accompanying statement of operations.

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

 

For the Year Ended

 

 

December 31,

 

 

2016

 

 

2015

 

 

2014

 

Permian Divestiture

$

4,297

 

 

$

(60,875

)

 

$

(228,956

)

Rockies Divestiture

 

(7,677

)

 

 

(56,917

)

 

 

3,127

 

F-19


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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 for 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 13 for additional information regarding this related party divestiture.

Note 5. 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, 2016 and 2015, 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, 2016 and December 31, 2015. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 9 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, 2016 and December 31, 2015 were based on estimated forward commodity prices (including nonperformance risk) and forward interest rate yield curves. Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled.  Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2016 and December 31, 2015 for each of the fair value hierarchy levels:

 

 

Fair Value Measurements at December 31, 2016 Using

 

 

Quoted Prices in

 

 

Significant Other

 

 

Significant

 

 

 

 

 

 

Active Market

 

 

Observable Inputs

 

 

Unobservable Inputs

 

 

 

 

 

 

(Level 1)

 

 

(Level 2)

 

 

(Level 3)

 

 

Fair Value

 

 

(In thousands)

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

$

 

 

$

189,851

 

 

$

 

 

$

189,851

 

Total assets

$

 

 

$

189,851

 

 

$

 

 

$

189,851

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

$

 

 

$

17,757

 

 

$

 

 

$

17,757

 

Total liabilities

$

 

 

$

17,757

 

 

$

 

 

$

17,757

 

 

 

F-20


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

 

Fair Value Measurements at December 31, 2015 Using

 

 

Quoted Prices in

 

 

Significant Other

 

 

Significant

 

 

 

 

 

 

Active Market

 

 

Observable Inputs

 

 

Unobservable Inputs

 

 

 

 

 

 

(Level 1)

 

 

(Level 2)

 

 

(Level 3)

 

 

Fair Value

 

 

(In thousands)

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

$

 

 

$

816,995

 

 

$

 

 

$

816,995

 

Interest rate derivatives

 

 

 

 

 

 

 

 

 

 

 

Total assets

$

 

 

$

816,995

 

 

$

 

 

$

816,995

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

$

 

 

$

84,501

 

 

$

 

 

$

84,501

 

Interest rate derivatives

 

 

 

 

2,655

 

 

 

 

 

 

2,655

 

Total liabilities

$

 

 

$

87,156

 

 

$

 

 

$

87,156

 

 

See Note 6 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 7 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.

 

(i)

During the year ended December 31, 2016, we recognized $183.4 million of impairments related to certain properties in East Texas. 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 and change in future planned development due to liquidity constraints as a result of our reduced borrowing base during the three months ended December 31, 2016. As a result of the impairments, the carrying value of these properties was reduced to approximately $156.2 million.

 

(ii)

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.  

 

(iii)

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. 

F-21


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 6. 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 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 $107.2 million against amounts outstanding under our revolving credit facility at December 31, 2016, reducing our maximum credit exposure to approximately $64.9 million, of which approximately $42.5 million was with a single counterparty. See Note 9 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.

In December 2016, in connection with our restructuring efforts, we monetized approximately $191.4 million in commodity hedges and used the proceeds to reduce amounts outstanding under our revolving credit facility.

During the periods of April through June 2016, we monetized approximately $39.3 million in commodity hedges and used the proceeds from the settlements to repurchase senior notes.

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.

Subsequent Event. In January 2017, in connection with our restructuring efforts, we monetized $94.1 million in commodity hedges and used a portion of the proceeds to reduce the amounts outstanding under our revolving credit facility and kept the remaining portion as cash on hand for general partnership purposes.

We enter into natural gas derivative contracts that are indexed to NYMEX Henry Hub. We also enter into oil derivative contracts indexed to either NYMEX WTI or Inter-Continental Exchange (“ICE”) Brent. Our NGL derivative contracts are indexed to OPIS Mont Belvieu.

F-22


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

At December 31, 2016, the Partnership had the following open commodity positions:

 

2017

 

 

2018

 

 

2019

 

Natural Gas Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

Fixed price swap contracts:

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

1,890,000

 

 

 

1,740,000

 

 

 

1,000,000

 

Weighted-average fixed price

$

3.86

 

 

$

3.83

 

 

$

3.47

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

Fixed price swap contracts:

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

184,500

 

 

 

182,000

 

 

 

70,000

 

Weighted-average fixed price

$

84.29

 

 

$

83.44

 

 

$

86.84

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

Fixed price swap contracts:

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

43,300

 

 

 

 

 

 

 

Weighted-average fixed price

$

37.55

 

 

$

 

 

$

 

 

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.

During December 2016, in connection with our restructuring efforts, we elected to terminate the interest rate swaps associated with our revolving credit facility and in the aggregate paid our counterparties approximately $2.1 million. The Partnership did not have any interest rate swaps at December 31, 2016.

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, 2016 and 2015. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement.

 

 

 

 

 

Asset Derivatives

 

 

Liability Derivatives

 

 

 

 

 

December 31,

 

 

December 31,

 

 

December 31,

 

 

December 31,

 

Type

 

Balance Sheet Location

 

2016

 

 

2015

 

 

2016

 

 

2015

 

 

 

 

 

(In thousands)

 

Commodity contracts

 

Short-term derivative instruments

 

$

86,335

 

 

$

324,265

 

 

$

16,871

 

 

$

53,581

 

Interest rate swaps

 

Short-term derivative instruments

 

 

 

 

 

 

 

 

 

 

 

1,214

 

Gross fair value

 

 

 

 

86,335

 

 

 

324,265

 

 

 

16,871

 

 

 

54,795

 

Netting arrangements

 

Short-term derivative instruments

 

 

(16,871

)

 

 

(51,945

)

 

 

(16,871

)

 

 

(51,945

)

Net recorded fair value

 

Short-term derivative instruments

 

$

69,464

 

 

$

272,320

 

 

$

 

 

$

2,850

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Long-term derivative instruments

 

$

103,515

 

 

$

492,730

 

 

$

885

 

 

$

30,920

 

Interest rate swaps

 

Long-term derivative instruments

 

 

 

 

 

 

 

 

 

 

 

1,441

 

Gross fair value

 

 

 

 

103,515

 

 

 

492,730

 

 

 

885

 

 

 

32,361

 

Netting arrangements

 

Long-term derivative instruments

 

 

(885

)

 

 

(30,920

)

 

 

(885

)

 

 

(30,920

)

Net recorded fair value

 

Long-term derivative instruments

 

$

102,630

 

 

$

461,810

 

 

$

 

 

$

1,441

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

F-23


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

(Gains) Losses on Derivatives

We do not designate derivative instruments as hedging instruments for accounting and financial reporting purposes. Accordingly, all gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations. The following table details the gains and losses related to derivative instruments for the years ending December 31, 2016, 2015, and 2014:

 

 

 

 

For the Year Ended

 

 

 

Statements of

 

December 31,

 

 

 

Operations Location

 

2016

 

 

2015

 

 

2014

 

Commodity derivative contracts

 

(Gain) loss on commodity derivatives

 

$

117,105

 

 

$

(462,890

)

 

$

(492,254

)

Interest rate derivatives

 

Interest expense, net

 

 

1,290

 

 

 

4,674

 

 

 

(151

)

 

Note 7. 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, 2016, 2015, and 2014:

 

2016

 

 

2015

 

 

2014

 

 

(in thousands)

 

Asset retirement obligations at beginning of period

$

164,164

 

 

$

112,702

 

 

$

101,436

 

Liabilities added from acquisitions or drilling

 

30

 

 

 

26,876

 

 

 

5,815

 

Liabilities removed upon sale of wells

 

(19,669

)

 

 

(3,412

)

 

 

 

Liabilities settled

 

(1,442

)

 

 

(1,430

)

 

 

(651

)

Accretion expense

 

10,231

 

 

 

7,125

 

 

 

5,773

 

Revision of estimates

 

2,388

 

 

 

22,303

 

 

 

329

 

Asset retirement obligations at end of period

 

155,702

 

 

 

164,164

 

 

 

112,702

 

Less: Current portion

 

789

 

 

 

1,175

 

 

 

 

Asset retirement obligations - long-term portion

$

154,913

 

 

$

162,989

 

 

$

112,702

 

 

Note 8. 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. During 2016, we replaced certain restricted investments with surety bonds. The components of the restricted investment balance are as follows:

 

 

December 31,

 

 

December 31,

 

 

2016

 

 

2015

 

 

(In thousands)

 

BOEM platform abandonment (See Note 14)

$

152,000

 

 

$

144,008

 

BOEM lease bonds

 

 

 

 

1,533

 

Surety bond cash collateral

 

500

 

 

 

 

 

 

 

 

 

 

 

 

SPBPC Collateral:

 

 

 

 

 

 

 

Contractual pipeline and surface facilities abandonment

 

3,627

 

 

 

3,178

 

California State Lands Commission pipeline right-of-way bond

 

 

 

 

3,005

 

City of Long Beach pipeline facility permit

 

 

 

 

500

 

Federal pipeline right-of-way bond

 

 

 

 

307

 

Port of Long Beach pipeline license

 

107

 

 

 

100

 

Restricted investments

$

156,234

 

 

$

152,631

 

 

F-24


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 9. Debt

Our consolidated debt obligations consisted of the following at the dates indicated:

 

December 31,

 

 

December 31,

 

 

2016

 

 

2015

 

 

(In thousands)

 

OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1)

$

511,652

 

 

$

836,000

 

2021 Senior Notes, fixed-rate, due May 2021 (2) (4)

 

646,287

 

 

 

700,000

 

2022 Senior Notes, fixed-rate, due August 2022 (3) (4)

 

464,965

 

 

 

496,990

 

Senior notes debt issuance costs, net (5)

 

 

 

 

(18,297

)

Unamortized discounts (5)

 

 

 

 

(14,114

)

Total debt

 

1,622,904

 

 

 

2,000,579

 

Current portion of long-term debt (6)

 

(1,622,904

)

 

 

 

Total long-term debt

$

 

 

$

2,000,579

 

 

 

(1)

The carrying amount of our revolving credit facility approximates fair value because the interest rates are variable and reflective of market rates.

 

(2)

The estimated fair value of our 2021 Senior Notes was $314.3 million and $210.0 million at December 31, 2016 and 2015, respectively.

 

(3)

The estimated fair value of our 2022 Senior Notes was $223.2 million and $149.1 million at December 31, 2016 and 2015, respectively.

 

(4)

The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

 

(5)

Approximately $25.0 million in net discounts and deferred financing fees were written off due to a default and event of default and the uncertainty regarding anticipated financial covenant violation at December 31, 2016.  

 

(6)

Due to an existing and anticipated financial covenant violations, the Partnership’s revolving credit facility and senior notes were classified as current at December 31, 2016.

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:

 

December 31,

 

 

2016

 

 

(In thousands)

 

OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018

$

530,653

 

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.

In January 2017, we monetized certain hedge positions and used a portion of the cash proceeds to repay outstanding borrowings under our revolving credit facility and kept the remaining portion as cash on hand for general partnership purposes. In conjunction with the hedge monetization, our borrowing base was reduced to $457.2 million on January 13, 2017. See Note 6 for additional information regarding the hedge monetization.

In December 2016, with the anticipation of the financial restructuring and to reduce exposure under the revolving credit facility, the Partnership monetized certain hedge positions and used the cash proceeds to repay outstanding borrowings under our revolving credit facility. In conjunction with the hedge monetization, our borrowing base was reduced from $720.0 million to $619.0 million on December 21, 2016 and then further reduced to $530.7 million on December 22, 2016. See Note 6 for additional information regarding the hedge monetization.

F-25


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

On November 1, 2016, the Partnership, OLLC, certain subsidiaries of the Partnership, the administrative agent, and the lenders under our revolving credit facility, dated as December 14, 2011 (as the context may require, as amended, supplemented or otherwise modified, the “Credit Agreement” or “revolving credit facility”) entered into the limited waiver and twelfth amendment (the “Waiver and Twelfth Amendment”) to the Credit Agreement. See discussion noted below under “Deferral of Interest Payment, Waiver and Forbearance Agreement” for additional information on the Waiver and Twelfth Amendment.

On October 28, 2016, we entered into an eleventh amendment to our Credit Agreement by and among the Partnership, OLLC, the administrative agent and the other agents and lenders party thereto (the “Eleventh Amendment”). The Eleventh Amendment, among other things, (i) pursuant to a regularly-scheduled semi-annual redetermination of the borrowing base, decreased our borrowing base from $925.0 million to $740.0 million, effective October 28, 2016, and scheduled a further decrease of the borrowing base to $720.0 million, which was effective December 1, 2016 and (ii) amended the Credit Agreement to add a new event of default limiting the Partnership’s, OLLC and their respective subsidiaries’ ability to call, make or offer to make any redemption of, or make any other payments in respect of the Partnership’s senior unsecured notes if, on a pro forma basis, the Partnership’s and its subsidiaries’ aggregate liquidity (unrestricted cash and cash equivalents plus amounts available to be drawn under the Credit Agreement), is less than $30.0 million.

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

 

establish a new Applicable Margin (as defined in the Credit Agreement) that ranges from 1.25% to 2.25% per annum (based on borrowing base usage) on alternate base rate loans and from 2.25% to 3.25% per annum (based on borrowing base usage) on Eurodollar or LIBOR loans and sets the committee fee for the unused portion of the borrowing base to 0.50% per annum regardless of the borrowing base usage;

 

reduce the borrowing base thereunder from $1,175 million to $925 million;

 

require the Partnership to maintain a ratio of Consolidated First Lien Net Secured Debt (as defined in the Credit Agreement) to Consolidated EBITDAX (as defined in the Credit Agreement) of not greater than 3.25 to 1.00 as of the end of each fiscal quarter;

 

permit the issuance by the Partnership of secured second lien notes solely in exchange for the Partnership’s outstanding senior unsecured notes pursuant to one or more senior debt exchanges; provided that, among other things: (i) such debt shall be (A) in an aggregate principal amount not to exceed $600 million (plus any principal representing payment of interest in kind) and (B) such debt is subject to an intercreditor agreement at all times; and (ii) such debt shall not (A) have any scheduled principal amortization or have a scheduled maturity date or a date of mandatory redemption in full prior to 180 days after March 19, 2018, or (B) not contain any covenants or events of default that are more onerous or restrictive than those set forth in the Credit Agreement other than covenants or events of default that are contained in the Partnership’s existing senior unsecured notes and (C) the Consolidated Net Interest Expense (as defined in the Credit Agreement) for the 12-month period following the exchange, after giving pro forma effect to the exchange, shall be no greater than the Consolidated Net Interest Expense for such period had the exchange not occurred;

 

permit the payment by the Partnership of cash distributions to its equity holders out of available cash in accordance with its partnership agreement so long as, among other things, the pro forma Availability (as defined in the Credit Agreement) shall be not less than the greater of $75 million or (x) 10% of the borrowing base then in effect with respect to any such distributions made prior to June 1, 2016 or (y) 15% of the borrowing base then in effect with respect to any such distributions made on or after June 1, 2016; provided that the aggregate amount of all such payments made in any fiscal quarter for which the ratio of the Partnership’s total debt at the time of such payment to its Consolidated EBITDAX for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available is greater than or equal to 4.00 to 1.00 will not exceed $4.15 million during such fiscal quarter;

F-26


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

 

permit the repurchase of the Partnership’s (i) outstanding senior unsecured notes, or if any, second lien debt with proceeds from Swap Liquidations (as defined in the Credit Agreement) or the sale or other disposition of oil and gas properties and (ii) outstanding senior unsecured notes with the proceeds from the release of cash securing certain governmental obligations located in the Beta Field offshore Southern California, provided that, among other things, (A) the pro forma Availability is not less than the greater of $75 million or (x) 10% of the borrowing base then in effect through May 31, 2016 or (y) 15% of the borrowing base then in effect on or after June 1, 2016, (B) the Partnership’s pro forma ratio of Consolidated First Lien Net Secured Debt to Consolidated EBITDAX is not greater than 3.00 to 1.00, and (C) the amount of proceeds from all Swap Liquidations and sales or other dispositions of oil and gas properties used to repurchase outstanding senior unsecured notes or secured second lien notes does not exceed $40 million in the aggregate, or in the case of the release of cash securing such obligations, the amount of proceeds used to repurchase outstanding senior unsecured notes does not exceed $60 million in the aggregate;

 

require that the oil and gas properties of the Partnership mortgaged as collateral security for the loans under the Credit Agreement represent not less than 90% of the total value of the oil and gas properties of the Partnership evaluated in the most recently completed reserve report; and

 

require the Partnership, in the event that at the close of any business day the aggregate amount of any unrestricted cash or cash equivalents exceeds $25 million in the aggregate, to prepay the loans under the Credit Agreement and cash collateralize any letter of credit exposure with such excess.

Due to (i) the uncertainty regarding the Partnership’s ability to cure the default and event of default as discussed in Note 2, (ii) our inability to comply with certain financial covenants contained in our revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes, the Partnership classified the outstanding revolving credit facility balance as a current liability on its balance sheet as of December 31, 2016. As a result of the Chapter 11 filing, the debt has been accelerated.

2021 Senior Notes

On April 17, 2013, May 23, 2013 and October 10, 2013, we and Finance Corp.’s (collectively, 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.

During the year ended December 31, 2016, the Partnership repurchased on the open market an aggregate principal amount of approximately $53.7 million of its 2021 Senior Notes. In connection with the repurchases, the Partnership paid approximately $26.4 million and recorded a gain of $27.5 million.

2022 Senior Notes  

On July 17, 2014, 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.

F-27


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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.

During the year ended December 31, 2016, the Partnership repurchased on the open market an aggregate principal amount of $32.0 million of its 2022 Senior Notes. In connection with the repurchases, the Partnership paid approximately $14.9 million and recorded a gain of $14.8 million. During the year ended December 31, 2015, the Partnership repurchased on the open market approximately $3.0 million of its 2022 Senior Notes. In connection with the repurchase, the Partnership paid approximately $2.9 million and recorded a gain on extinguishment of debt of approximately $0.4 million.

Deferral of Interest Payment, Waiver and Forbearance Agreements

In November 2016, we elected to defer an approximately $24.6 million interest payment due on November 1, 2016 with respect to the 2021 Senior Notes. The interest payment was subject to a 30-day grace period under the indenture. Failure to pay such interest payment on November 1, 2016 would have resulted in certain defaults and events of default under our revolving credit facility, which defaults were waived by the lenders under the our revolving credit facility.

Pursuant to the Waiver and Twelfth Amendment, the requisite lenders under the Credit Agreement agreed to the limited waiver of certain defaults and events of default that would have occurred under the Credit Agreement as a result of the Issuers election to avail themselves of the 30-day grace period under the indenture governing the Issuers’ 2021 Senior Notes for the payment of the semi-annual interest payment in respect to such senior notes due November 1, 2016.

Further pursuant to the Waiver and Twelfth Amendment, from the date thereof until November 30, 2016 (such period from November 1, 2016 to November 30, 2016, the “Waiver Period”), the Partnership and OLLC agreed to pay 100% of the net cash proceeds from any asset sale, transfer or other disposition (including with respect to notes receivable and accounts receivable) and from the liquidation of any swap transaction or hedge transaction arising under swap or hedge agreements between or among the Partnership, OLLC and/or any other loan party and any lender under the Credit Agreement and/or its affiliates, in each case, to the administrative agent for the ratable account of each lender under the Credit Agreement, for application to the outstanding loans under the Credit Agreement. Amounts so applied would have also reduced the aggregate elected commitments of the lenders under the Credit Agreement by an equivalent amount.

Further, pursuant to the Waiver and Twelfth Amendment, from the date thereof until the termination of the Waiver Period the Partnership and OLLC agreed, to additional restrictive covenants. These restrictions further limited, until the expiration of the Waiver Period, the ability of, among other things, the Partnership, OLLC and certain of their respective subsidiaries from incurring additional indebtedness, creating liens on assets, paying certain dividends and distributions, making any optional or voluntary payments or redemptions in respect of any other indebtedness, making investments (including in respect of the creation of subsidiaries), entering into certain lease agreements, entering into certain business combinations, entering into any sale-leaseback transaction and entering into certain transactions with affiliates.

Finally, pursuant to the Waiver and Twelfth Amendment, the Partnership and OLLC agreed to amend, to be effective from and after the date of the Waiver and Twelfth Amendment, subject to the Chapter 11 proceedings, the Credit Agreement to increase, from 90% to 95% (or such lesser amount agreed to by the administrative agent in its sole discretion, which lesser amount shall not be less than 92%), the percentage of the total value of OLLC’s and its subsidiary-loan parties’ oil and gas properties subject to a mortgage or similar instruments in favor of the administrative agent.

On November 30, 2016, the Partnership, OLLC, certain subsidiaries of the partnership, the administrative agent, and the lenders consenting thereto entered into the first amendment to the limited waiver under our revolving credit facility, extending the Waiver Period to December 16, 2016.

On November 30, 2016, the Partnership entered into (i) a forbearance (the “2021 Notes Forbearance”) among the Issuers, certain guarantors party thereto, and certain beneficial owners and/or investment advisors or managers of discretionary accounts for the holders or beneficial owners (the “2021 Holders”) of 51.7% of the aggregate principal amount of the Partnership’s 2021 Senior Notes and (ii) a Forbearance (the “2022 Notes Forbearance” and, together with the 2021 Notes Forbearance, the “Forbearances”) among the Issuers, certain guarantors party thereto, and certain beneficial owners and/or investment advisors or managers of discretionary accounts for the holders or beneficial owners (the “2022 Holders”) of 69% of the aggregate principal amount of the Partnership’s 2022 Senior Notes.

F-28


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Pursuant to each Forbearance, among other provisions, each of the 2021 Holders and 2022 Holders agreed that during the forbearance period, subject to certain conditions, they would not enforce, or otherwise take any action to direct enforcement of, any of the rights and remedies available to the 2021 Holders, the 2022 Holders or the trustee, as applicable, including, without limitation, any action to accelerate, or join in any request for acceleration of, the 2021 Senior Notes or the 2022 Senior Notes, solely with respect to the failure to make the interest payment due on November 1, 2016 on the 2021 Senior Notes, and the subsequent default for 30 days in such payment, which constituted an event of default under the 2021 Senior Notes indenture and may result in a cross default under the 2022 Senior Notes indenture. The forbearance agreements initially extended through December 7, 2016, and were subsequently extended through December 16, 2016.

On December 16, 2016, the Partnership, OLLC, certain subsidiaries of the partnership, the administrative agent, and the lenders consenting thereto entered into the second amendment to limited waiver under our revolving credit facility, which among other things, extending the Waiver Period to January 13, 2017. In addition, the forbearance agreements were extended through January 13, 2017. 

 On December 22, 2016, the Partnership entered into a Plan Support Agreement (the “Noteholder PSA”) with holders of over an aggregate of 50.2% of the aggregate outstanding principal amount of the 2021 Senior Notes and the 2022 Senior Notes (collectively, the “Notes”), as well as reached an agreement-in-principle with the administrative agent under our revolving credit facility on the terms of a financial restructuring. Under the terms of the Noteholder PSA, the financial restructuring would be effected through a prepackaged or prenegotiated plan of reorganization (the “Plan”). Pursuant to the terms of the Plan, which would be subject to approval of the Bankruptcy Court, it is anticipated that, among other things, on the effective date of the Plan (the “Effective Date”):

 

A newly formed corporation, as successor to the Partnership (“Reorganized Memorial”) would issue (i) new common shares (the “New Common Shares”) and (ii) five year warrants (the “Warrants”) entitling their holders upon exercise thereof, on a pro rata basis, to 8% of the total issued and outstanding New Common Shares, at a per share exercise price equal to the principal and accrued interest on the senior notes as of December 31, 2016, divided by the number of issued and outstanding New Common Shares (including New Common Shares issuable upon exercise of the Warrants), which New Common Shares and Warrants will be distributed as set forth below;

 

The Notes would be cancelled and discharged and the holders of those Notes would receive (directly or indirectly) New Common Shares representing, in the aggregate, 98% of the New Common Shares issued on the Effective Date (subject to dilution by the post-emergence management incentive plan and the New Common Shares issuable upon exercise of the Warrants);

 

The noteholders, at their election, would be entitled to receive an additional cash payment of up to approximately $24.6 million;

 

Each holder of existing equity interests in the Partnership would receive its pro rata share of (i) New Common Shares representing, in the aggregate, 2% of the New Common Shares issued on the Effective Date and (ii) the Warrants (in each case, subject to dilution by the post-emergence management incentive plan and, in the case of the New Common Shares, subject to dilution by the Warrants);

 

General unsecured claims, on or after the effective date, would be paid in the ordinary course; and

 

Reorganized Memorial would enter an Exit Credit Facility, in the form of an amendment and restatement of the existing revolving credit facility. See Note 2 for additional information related to the expected terms of the Exit Credit Facility.

The Partnership expects to emerge from the Chapter 11 proceedings as a corporation, including for U.S. federal income tax purposes.

On January 13, 2017, the Partnership entered into the third amendment to limited waiver, which extended the outside date of the Waiver Period from January 13, 2017 to January 16, 2017. In addition, the Partnership entered into a Plan Support Agreement (the “RBL PSA”) with lenders holding 100% of the loans under our revolving credit facility. The RBL PSA was entered into on terms substantially similar to those of the Noteholder PSA. In addition, among other things, the RBL PSA provided that (i) the consenting lenders (as defined in the RBL PSA) may terminate the RBL PSA upon the termination of the Noteholder PSA or if there is an amendment to the Noteholder PSA that is, or would reasonably be expected to be, adverse to the administrative agent under our revolving credit facility or the Consenting Lenders and (ii) each of the Debtors agreed to not file a voluntary petition for relief under Chapter 11 until the Debtors terminated certain swap agreements identified in the RBL PSA and used the net proceeds thereof to repay outstanding amounts under the revolving credit facility.

F-29


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

The Partnership did not pay the interest due on the 2021 Senior Notes prior to the expiration of the 30-day grace period. Due to (i) the uncertainty regarding the Partnership’s ability to cure the default and event of default as discussed in Note 2, (ii) our inability to comply with certain financial covenants contained in our revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes, the Partnership classified the outstanding balance of the senior notes as a current liability on its balance sheet as of December 31, 2016. As a result of the Chapter 11 filing, the debt has been accelerated.

Weighted-Average Interest Rates

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

 

For the Year Ended

 

 

December 31,

 

 

2016

 

 

2015

 

 

2014

 

OLLC revolving credit facility (1)

 

3.28%

 

 

 

2.12%

 

 

 

2.67%

 

 

 

(1)

The Applicable Margin (as defined in our revolving credit facility), or credit spread, varies based on the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect). The Applicable Margin for the year ended for December 31, 2016, 2015, and 2014 was 2.76%, 1.90%, and 1.80% respectively.

Deferred Financing Costs

At December 31, 2016, approximately $1.3 million in deferred financing fees were written off related to our revolving credit facility, approximately $8.5 million were written off for the 2021 Senior Notes and approximately $5.7 million were written off for the 2022 Senior Notes due to (i) the uncertainty regarding the Partnership’s ability to cure the default as discussed in Note 2, (ii) our inability to comply with certain financial covenants contained in our revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes.

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

 

December 31,

 

 

December 31,

 

 

2016 (3)

 

 

2015

 

 

(In thousands)

 

OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1)

$

 

 

$

3,672

 

2021 Senior Notes (2)

 

 

 

 

11,194

 

2022 Senior Notes (2)

 

 

 

 

7,103

 

Total

$

 

 

$

21,969

 

 

 

(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.

 

(3)

At December 31, 2016, there were no remaining unamortized deferred financing costs as such costs were written off due to a default and event of default and the uncertainty regarding anticipated financial covenant violation at December 31, 2016. See discussion noted above.

Letters of credit

At December 31, 2016, we had $2.4 million letters of credit outstanding, all related to operations at our Wyoming properties.

Note 10. Equity and Distributions

2015 Purchase of Noncontrolling Interest

In connection with the 2015 Beta Acquisition, we purchased the noncontrolling interests in SPBPC. See Note 4 for further information.

F-30


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.

Equity Outstanding

The following table summarizes changes in the number of outstanding units since December 31, 2013:

 

 

 

 

 

 

 

 

 

General

 

 

Common

 

 

Subordinated

 

 

Partner

 

Balance, December 31, 2013

 

55,877,831

 

 

 

5,360,912

 

 

 

61,300

 

Common units issued

 

24,840,000

 

 

 

 

 

 

 

Restricted common units issued

 

684,954

 

 

 

 

 

 

 

Restricted common units forfeited

 

(38,294

)

 

 

 

 

 

 

Restricted common units repurchased (1)

 

(42,587

)

 

 

 

 

 

 

Common units repurchased under repurchase program

 

(899,912

)

 

 

 

 

 

 

General partner units issued

 

 

 

 

 

 

 

25,497

 

Balance, December 31, 2014

 

80,421,992

 

 

 

5,360,912

 

 

 

86,797

 

Restricted common units issued

 

827,704

 

 

 

 

 

 

 

Restricted common units forfeited

 

(69,059

)

 

 

 

 

 

 

Restricted common units repurchased (1)

 

(87,228

)

 

 

 

 

 

 

Common units repurchased under repurchase program

 

(3,547,921

)

 

 

 

 

 

 

Subordinated units converted to common units

 

5,360,912

 

 

 

(5,360,912

)

 

 

 

Balance, December 31, 2015

 

82,906,400

 

 

 

 

 

 

86,797

 

Common units issued

 

1,178,102

 

 

 

 

 

 

 

 

 

Restricted common units issued

 

50,000

 

 

 

 

 

 

 

Restricted common units forfeited

 

(27,537

)

 

 

 

 

 

 

Restricted common units repurchased (1)

 

(279,045

)

 

 

 

 

 

 

Cancellation of general partner units

 

 

 

 

 

 

 

(86,797

)

Balance, December 31, 2016

 

83,827,920

 

 

 

 

 

 

 

 

 

(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 $0.6 million, $1.3 million and $1.0 million for the years ended December 31, 2016, 2015 and 2014, 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.

Restricted common units are a component of common units as presented on our consolidated balance sheets. See Note 12 for additional information regarding restricted common units that were granted during the years ended December 31, 2016, 2015 and 2014.

General Partner Interest and IDRs. On April 27, 2016, we acquired MEMP GP from Memorial Resource for cash consideration of approximately $0.8 million. MEMP GP held an approximate 0.1% general partner interest and 50% of the IDRs in us. In conjunction with the MEMP GP Acquisition, on April 27, 2016, we also entered into an agreement with an NGP affiliate pursuant to which we agreed to acquire the other 50% of the IDRs. The acquisition was accounted for as an equity transaction and no gain or loss was recognized as a result of the acquisition. In connection with the MEMP GP Acquisition, our partnership agreement was amended and restated to convert the 0.1% general partner interest in the Partnership held by MEMP GP into a non-economic general partner interest. Prior to June 1, 2016, Memorial Resource owned 100% of our general partner, which owned 50% of our incentive distribution rights. The Funds collectively indirectly owned 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.

F-31


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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.

“At-the-Market” Equity Program

On May 25, 2016, the Partnership entered into an equity distribution agreement for the sale of up to $60.0 million of common units under an at-the-market program (the “ATM Program”). Sales of common units, if any, will be made under the ATM Program by means of ordinary brokers’ transactions, through the facilities of the NASDAQ Global Market at market prices, or as otherwise agreed between the Partnership and a sales agent.

During the year ended December 31, 2016, the Partnership sold 1,178,102 common units under the ATM program. The sale of the units generated proceeds of approximately $1.8 million for the year ended December 31, 2016, which was net of approximately $0.5 million in fees. The Partnership used the net proceeds from the sale of common units to repurchase senior notes.

2015 and 2014 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. The MEMP Repurchase Program expired in December 2015.

Allocations of Net Income (Loss)

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

Cash Distribution Policy

In October 2016, the board of directors of our general partner suspended distributions on common units primarily due to the current and expected commodity price environment and market conditions and their impact on our future business as well as restrictions imposed by our debt instruments, including our revolving credit facility. 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.

Available Cash. Our amended partnership agreement requires that within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to our 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 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.

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.

F-32


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Cash Distributions to Unitholders

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Distribution

 

 

 

 

 

 

 

 

 

Amount

 

 

Aggregate

 

 

Received by

 

Quarter

 

Declaration Date

 

Record Date

 

Payment Date

 

Per Unit

 

 

Distribution

 

 

Affiliates

 

2nd Quarter 2016

 

July 26, 2016

 

August 5, 2016

 

August 12, 2016

 

$

0.0300

 

 

$

2.5

 

 

$

< 0.1

 

1st Quarter 2016

 

April 26, 2016

 

May 6, 2016

 

May 13, 2016

 

$

0.0300

 

 

$

2.5

 

 

$

< 0.1

 

4th Quarter 2015

 

January 26, 2016

 

February 5, 2016

 

February 12, 2016

 

$

0.1000

 

 

$

8.3

 

 

$

< 0.1

 

3rd Quarter 2015

 

October 26, 2015

 

November 5, 2015

 

November 12, 2015

 

$

0.3000

 

 

$

24.9

 

 

$

< 0.1

 

2nd Quarter 2015

 

July 24, 2015

 

August 5, 2015

 

August 12, 2015

 

$

0.5500

 

 

$

45.7

 

 

$

0.1

 

1st Quarter 2015

 

April 24, 2015

 

May 6, 2015

 

May 13, 2015

 

$

0.5500

 

 

$

46.3

 

 

$

0.2

 

4th Quarter 2014

 

January 26, 2015

 

February 5, 2015

 

February 12, 2015

 

$

0.5500

 

 

$

46.3

 

 

$

3.1

 

3rd Quarter 2014

 

October 23, 2014

 

November 5, 2014

 

November 12, 2014

 

$

0.5500

 

 

$

47.8

 

 

$

3.1

 

2nd Quarter 2014

 

July 24, 2014

 

August 5, 2014

 

August 12, 2014

 

$

0.5500

 

 

$

39.5

 

 

$

3.0

 

1st Quarter 2014

 

April 24, 2014

 

May 6, 2014

 

May 13, 2014

 

$

0.5500

 

 

$

33.8

 

 

$

3.0

 

 

Previous Owners Capital

The following table summarizes our previous owners’ equity transactions related to the Property Swap with respect to the period indicated (dollars in thousands):

 

Previous Owners

 

Balance, December 31, 2013

$

283,405

 

Net income (loss)

 

(2,465

)

Contributions

 

5,990

 

Distributions

 

(9,886

)

Distribution of net asset to MRD Holdco

 

(26,131

)

Tax related effects attributable to Memorial Resource restructuring transactions and initial public offering

 

(30,483

)

Other

 

227

 

Balance, December 31, 2014

$

220,657

 

Net income (loss)

 

(2,268

)

Contributions

 

1,912

 

Net book value of net assets exchanged

 

(248,321

)

Deferred tax liability retained by previous owner

 

28,020

 

Balance, December 31, 2015

$

 

 

F-33


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 11. 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):

 

For the Year Ended

 

 

December 31,

 

 

2016

 

 

2015

 

 

2014

 

Net income (loss) attributable to Memorial Production Partners LP

$

(540,398

)

 

$

(395,877

)

 

$

115,582

 

Less: Previous owners interest in net income (loss)

 

 

 

 

(2,268

)

 

 

(2,465

)

Less: General partner's 0.1% interest in net income (loss) (1)

 

(168

)

 

 

(412

)

 

 

118

 

Less: IDRs attributable to corresponding period

 

 

 

 

112

 

 

 

202

 

Net income (loss) available to limited partners

$

(540,230

)

 

$

(393,309

)

 

$

117,727

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average limited partner units outstanding:

 

 

 

 

 

 

 

 

 

 

 

Common units

 

83,351

 

 

 

82,897

 

 

 

65,498

 

Subordinated units

 

 

 

 

631

 

 

 

5,361

 

Total (2)

 

83,351

 

 

 

83,528

 

 

 

70,859

 

Basic and diluted EPU

$

(6.48

)

 

$

(4.71

)

 

$

1.66

 

 

 

(1)

As a result of repurchases under the MEMP Repurchase Program, our general partner had an approximate average 0.105% interest in us prior to the MEMP GP Acquisition for the five months ended May 31, 2016 and an approximate average of 0.105% interest in us for the year ended December 31, 2015.

 

 

(2)

For the year ended December 31, 2016, 3,325,318 incremental phantom units under the treasury stock method were excluded from the calculation of diluted earnings per unit, due to their antidilutive effect as we were in a loss position.

 

Note 12. Equity-based Awards

Long-Term Incentive Plan

In December 2011, the board of directors of our general partner 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, who perform services for the Partnership. The LTIP authorizes the grant 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 of directors of our general partner or a committee thereof. During the years ended December 31, 2016, 2015 and 2014 there were multiple awards of restricted common units that were granted under the LTIP to executive officers and independent directors of our general partner 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. 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 employees during the years ended December 31, 2016, 2015 and 2014 was $0.1 million, $12.3 million and $15.0 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.

F-34


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:

 

 

 

 

 

Weighted-

 

 

 

 

 

 

Average Grant

 

 

Number of

 

 

Date Fair Value

 

 

Units

 

 

per Unit (1)

 

Restricted common units outstanding at December 31, 2013

 

706,927

 

 

$

18.62

 

Granted (2)

 

684,954

 

 

$

22.39

 

Forfeited

 

(38,294

)

 

$

20.54

 

Vested

 

(260,067

)

 

$

18.56

 

Restricted common units outstanding at December 31, 2014

 

1,093,520

 

 

$

20.93

 

Granted (3)

 

827,704

 

 

$

14.90

 

Forfeited

 

(69,059

)

 

$

18.35

 

Vested

 

(483,627

)

 

$

20.37

 

Restricted common units outstanding at December 31, 2015

 

1,368,538

 

 

$

17.61

 

Granted (4)

 

50,000

 

 

$

2.41

 

Forfeited

 

(27,537

)

 

$

16.99

 

Vested

 

(958,841

)

 

$

18.01

 

Restricted common units outstanding at December 31, 2016

 

432,160

 

 

$

15.00

 

 

 

(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 2014 was $15.3 million based on grant date market prices ranging from of $21.99 to $23.40 per unit.

 

(3)

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.

 

(4)

The aggregate grant date fair value of restricted common unit awards issued in 2016 was $0.1 million based on grant date market price of $2.41 per unit.

LTIP Modification

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

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

Phantom Units

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

 

Number of

 

 

Units

 

Phantom units outstanding at December 31, 2015

 

 

Granted

 

6,169,018

 

Forfeited

 

(188,325

)

Phantom units outstanding at December 31, 2016

 

5,980,693

 

Phantom units issued to non-employee directors in January 2016 will vest on the first anniversary of the date of grant. Phantom units issued to certain employees in June 2016 will vest in substantially equal one-third increments on the first, second, and third anniversaries of the date of grant. The awards included distribution equivalent rights (“DERs”) pursuant to which the recipient will receive a cash payment with respect to each phantom unit equal to any cash distributions that we pay to a holder of a common unit. DERs are treated as additional compensation expense. Upon vesting, the phantom units will be settled through an amount of cash in a single lump sum payment equal to the product of (y) the closing price of our common units on the vesting date and (z) the number of such vested phantom units. In lieu of a cash payment, the board of directors of our general partner, in its discretion, may elect for the recipient to receive either a number of common units equal to the number of such vested phantom units or a combination of cash and common units. For the year ended December 31, 2016, the phantom units issued are classified as liability awards due to the Partnership not having sufficient common units available under the LTIP to settle in common units upon vesting.

F-35


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Compensation Expense

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):

 

For the Year Ended

 

 

December 31,

 

 

2016

 

 

2015

 

 

2014

 

Equity classified awards

 

 

 

 

 

 

 

 

 

 

 

Restricted common units

$

7,206

 

 

$

10,809

 

 

$

7,874

 

Liability classified awards

 

 

 

 

 

 

 

 

 

 

 

Phantom units

 

322

 

 

 

 

 

 

 

 

$

7,528

 

 

$

10,809

 

 

$

7,874

 

 

The unrecognized compensation cost associated with restricted common unit awards was an aggregate $3.8 million at December 31, 2016. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.1 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, 2016, 2015 and 2014, the restricted common unitholders received a distribution of approximately $0.2 million, $2.8 million and $1.9 million, respectively.

Note 13. Related Party Transactions

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

NGP Affiliated Companies

During the year ended December 31, 2016 and 2015, we paid less than $0.1 million and $0.3 million, respectively, to Multi-Shot, LLC, an NGP affiliated company, for services related to our drilling and completion activities.

Common Control Acquisitions

2016 Acquisition

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

F-36


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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 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):

 

Accounts receivable

$

2,372

 

Other receivables

 

5,478

 

Prepaid expenses and other current assets

 

1,874

 

Property and equipment, net

 

263,210

 

Accounts payable

 

(3,586

)

Accounts payable - affiliate

 

(1,290

)

Revenues payable

 

(1,110

)

Accrued liabilities

 

(11,347

)

Asset retirement obligations

 

(4,559

)

Net assets

$

251,042

 

 

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 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):

 

Double A

 

 

Wattenberg

 

 

Acquisition

 

 

Acquisition

 

Property and equipment, net

$

37,838

 

 

$

9,822

 

Asset retirement obligations

 

(908

)

 

 

(149

)

Other current liabilities

 

(722

)

 

 

 

Net assets

$

36,208

 

 

$

9,673

 

Due to common control considerations, the difference between the purchase price and the total identifiable assets has been recorded as a contribution or distribution, respectively, on our Statements of Consolidated and Combined Equity.  

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 with a net value of approximately $0.2 million to an affiliate of NGP for a purchase price of approximately $0.9 million. Due to common control considerations, $0.7 million difference between the proceeds from the sale and the net book value of the properties was recognized in the equity statement as a contribution.

Related Party Agreements

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

F-37


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Omnibus Agreement

Memorial Resource provided management, administrative and operating services to the Partnership and our general partner pursuant to our omnibus agreement. Upon completion of the MEMP GP Acquisition, the omnibus agreement was terminated and the Partnership entered into a transition services agreement with Memorial Resource. See Note 14 for additional information related to the transition services agreement. The following table summarizes the amount of general and administrative expenses recognized under the omnibus agreement that are reflected in the accompanying statements of operations for the periods presented (in thousands):

 

For the Year Ended

 

December 31,

 

2016

 

 

2015

 

 

2014

 

$

11,867

 

 

$

32,281

 

 

$

24,372

 

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 (“Beta Operating”), 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.

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

Transition Service Agreements

The Partnership entered into transition service agreements related to an October 2013 common control acquisition. 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.  

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 a contribution of approximately $2.1 million in the equity statement. Prior to the assignment from Classic Pipeline, for the years ended December 31, 2015 and 2014, the Partnership incurred gathering and salt water disposal fees of approximately $3.2 million and $1.8 million respectively, from Classic Pipeline, an affiliate.

 

F-38


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 14. Commitments and Contingencies

Transition Services Agreement

On June 1, 2016 we closed the MEMP GP Acquisition. Upon closing of the MEMP GP Acquisition, we and Memorial Resource became unaffiliated entities. We terminated our omnibus agreement and entered into a transition services agreement with Memorial Resource to manage post-closing separation costs and activities. During the year ended December 31, 2016, we recorded $1.6 million, of general and administrative expenses related to the transition services agreement with Memorial Resource.

Litigation & Environmental

On January 16, 2017, the Debtors filed voluntary petitions under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. As a result of the Chapter 11 proceedings, attempts to prosecute, collect, secure or enforce remedies with respect to pre-petition claims against the Debtors are subject to the automatic stay provisions of Section 362(a) of the Bankruptcy Code, including litigation relating to the entities involved in the Chapter 11 proceedings. See Note 2 for additional information.

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

Environmental costs for remediation are accrued 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. 

The following table presents the activity of our environmental reserves for the periods presented:

 

 

2016

 

 

2015

 

 

2014

 

 

 

(In thousands)

 

Balance at beginning of period

 

$

216

 

 

$

2,092

 

 

$

437

 

Charged to costs and expenses

 

 

 

 

 

 

 

 

2,852

 

Payments

 

 

(216

)

 

 

(1,876

)

 

 

(1,197

)

Balance at end of period

 

$

 

 

$

216

 

 

$

2,092

 

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

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, 2016, the account balance included in restricted investments was approximately $3.6 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 quarterly payments to the trust account of no less than $1.25 million in response to the revision. The trust account has the required minimum balances of $152.0 million at December 31, 2016.

F-39


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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. 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 2017 after negotiations are completed.

The gross held-to-maturity investments held in the trust account as of December 31, 2016 for the U.S. Bank money market cash equivalent was $152.0 million.

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, 2016, 2015 and 2014, we recognized $10.9 million, $16.9 million and $6.4 million of rent expense, respectively. The previous owners recorded rent expense of approximately $0.5 million for the year ended December 31, 2014.

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):

 

 

 

 

 

 

Payment or Settlement Due by Period

 

Purchase commitment

 

Total

 

 

2017

 

 

2018

 

 

2019

 

 

2020

 

 

2021

 

 

Thereafter

 

Operating leases

 

$

24,922

 

 

$

7,938

 

 

$

5,058

 

 

$

3,309

 

 

$

3,083

 

 

$

2,748

 

 

$

2,786

 

Purchase Commitments

At December 31, 2016, we had a CO2 purchase commitment with a third party associated with our Wyoming Bairoil properties. The price we will pay for CO2 generally varies depending on the amount of CO2 delivered and the price of oil. The table below outlines our purchase commitments under these contracts based on pricing at December 31, 2016 (in thousands):

 

 

 

 

 

 

Payment or Settlement Due by Period

 

Purchase commitment

 

Total

 

 

2017

 

 

2018

 

 

2019

 

 

2020

 

 

2021

 

 

Thereafter

 

CO2 minimum purchase commitment

 

$

19,665

 

 

$

6,740

 

 

$

4,567

 

 

$

4,548

 

 

$

3,810

 

 

$

 

 

$

 

Minimum Volume Commitment

At December 31, 2016, we had a long-term 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):

 

 

 

 

 

 

Payment or Settlement Due by Period

 

Purchase commitment

 

Total

 

 

2017

 

 

2018

 

 

2019

 

 

2020

 

 

2021

 

 

Thereafter

 

Midstream services

 

$

30,668

 

 

$

5,121

 

 

$

5,106

 

 

$

5,107

 

 

$

5,106

 

 

$

5,121

 

 

$

5,107

 

 

Note 15. Income Tax

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

 

For the Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

 

(In thousands)

 

Current taxes:

 

 

 

 

 

 

 

 

 

 

 

Federal

$

6

 

 

$

(11

)

 

$

 

State

 

8

 

 

 

(48

)

 

 

(127

)

Total current income tax benefit (expense)

 

14

 

 

 

(59

)

 

 

(127

)

Deferred taxes:

 

 

 

 

 

 

 

 

 

 

 

Federal

 

8

 

 

 

1,193

 

 

 

2,057

 

State

 

(195

)

 

 

1,041

 

 

 

(509

)

Total deferred income tax benefit (expense)

 

(187

)

 

 

2,234

 

 

 

1,548

 

Total income tax benefit (expense)

$

(173

)

 

$

2,175

 

 

$

1,421

 

F-40


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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

 

For the Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

Expected tax benefit (expense) at federal statutory rate

$

191,870

 

 

$

139,183

 

 

$

(39,966

)

State income tax benefit (expense), net of federal benefit

 

382

 

 

 

645

 

 

 

(1,907

)

Pass-through entities (1)

 

(191,921

)

 

 

(137,704

)

 

 

42,000

 

Other

 

(504

)

 

 

51

 

 

 

1,294

 

Total income tax benefit (expense)

$

(173

)

 

$

2,175

 

 

$

1,421

 

 

 

(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:

 

December 31,

 

 

2016

 

 

2015

 

 

(In thousands)

 

Deferred income tax assets:

 

 

 

 

 

 

 

Net operating loss carryforward

$

9

 

 

$

56

 

Asset retirement obligation

 

875

 

 

 

694

 

Other

 

33

 

 

 

38

 

Total deferred income tax assets:

 

917

 

 

 

788

 

Valuation allowance

 

(865

)

 

 

 

Net deferred income tax assets

 

52

 

 

 

788

 

 

 

 

 

 

 

 

 

Deferred income tax liabilities:

 

 

 

 

 

 

 

Property, plant and equipment

$

1,522

 

 

$

1,324

 

Derivatives

 

770

 

 

 

1,514

 

Other

 

40

 

 

 

44

 

Total deferred income tax liabilities

 

2,332

 

 

 

2,882

 

 

 

 

 

 

 

 

 

Net deferred income tax liabilities

$

2,280

 

 

$

2,094

 

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.

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, 2016.

Tax Audits and Settlements.  Generally, our income tax years 2011 through 2016 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, 2016, we had federal net operating loss of less than $0.1 million, which would expire in 2031. Valuation allowance was established on deferred tax assets applicable to a state jurisdiction where realization of the related deferred tax assets from future taxable income is not reasonably assured.

F-41


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 16. 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.  

 

First

 

 

Second

 

 

Third

 

 

Fourth

 

 

Quarter

 

 

Quarter

 

 

Quarter

 

 

Quarter

 

 

(In thousands, except per unit amounts)

 

For the Year Ended December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

60,866

 

 

$

68,066

 

 

$

74,222

 

 

$

81,426

 

Operating income (loss)

 

(5,449

)

 

 

(156,971

)

 

 

(6,336

)

 

 

(267,783

)

Net income (loss)

 

(38,097

)

 

 

(147,550

)

 

 

(32,866

)

 

 

(321,885

)

Net income (loss) attributable to Memorial Production Partners LP

 

(38,097

)

 

 

(147,550

)

 

 

(32,866

)

 

 

(321,885

)

Limited partners’ interest in net income (loss)

 

(38,057

)

 

 

(147,422

)

 

 

(32,866

)

 

 

(321,885

)

Basic and diluted earnings per unit

 

(0.46

)

 

 

(1.78

)

 

 

(0.39

)

 

 

(3.85

)

 

 

First

 

 

Second

 

 

Third

 

 

Fourth

 

 

Quarter

 

 

Quarter

 

 

Quarter

 

 

Quarter

 

 

(In thousands, except per unit amounts)

 

For the Year Ended December 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

92,818

 

 

$

98,138

 

 

$

88,083

 

 

$

79,108

 

Operating income (loss)

 

(136,370

)

 

 

(85,197

)

 

 

(160,844

)

 

 

99,434

 

Net income (loss)

 

(162,658

)

 

 

(113,859

)

 

 

(191,981

)

 

 

73,007

 

Net income (loss) attributable to Memorial Production Partners LP

 

(162,817

)

 

 

(113,924

)

 

 

(192,085

)

 

 

72,949

 

Net income (loss) allocated to previous owners

 

(2,268

)

 

 

 

 

 

 

 

 

 

Net income (loss) noncontrolling interest

 

159

 

 

 

65

 

 

 

104

 

 

 

58

 

Limited partners’ interest in net income (loss)

 

(160,439

)

 

 

(113,862

)

 

 

(191,938

)

 

 

72,874

 

Basic and diluted earnings per unit

 

(1.90

)

 

 

(1.36

)

 

 

(2.31

)

 

 

0.88

 

See Notes 3 and 11 for additional information regarding earnings per unit.

Note 17. 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.

 

Years Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

 

(In thousands)

 

Evaluated oil and natural gas properties

$

3,115,012

 

 

$

3,616,325

 

 

$

3,329,338

 

Support equipment and facilities

 

199,093

 

 

 

205,876

 

 

 

198,088

 

Accumulated depletion, depreciation, and amortization

 

(1,743,274

)

 

 

(1,878,549

)

 

 

(1,060,114

)

Total

$

1,570,831

 

 

$

1,943,652

 

 

$

2,467,312

 

 

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:

 

Years Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

 

(In thousands)

 

Property acquisition costs, proved

$

 

 

$

77,834

 

 

$

983,076

 

Property acquisition costs, unproved

 

 

 

 

1,887

 

 

 

720

 

Exploration

 

792

 

 

 

2,078

 

 

 

 

Development

 

54,310

 

 

 

233,241

 

 

 

308,724

 

Total

$

55,102

 

 

$

315,040

 

 

$

1,292,520

 

F-42


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

 

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.

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, 2016. 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:

 

2016

 

 

2015

 

 

2014

 

Oil ($/Bbl):

 

 

 

 

 

 

 

 

 

 

 

WTI (1)

$

42.75

 

 

$

46.79

 

 

$

91.48

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL ($/Bbl):

 

 

 

 

 

 

 

 

 

 

 

WTI (1)

$

42.75

 

 

$

46.79

 

 

$

91.48

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas ($/MMbtu):

 

 

 

 

 

 

 

 

 

 

 

Henry Hub (2)

$

2.48

 

 

$

2.58

 

 

$

4.35

 

 

 

(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.

F-43


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

The following tables set forth estimates of the net reserves as of December 31, 2016, 2015 and 2014, respectively:

 

Year Ended December 31, 2016

 

 

Oil

 

 

Gas

 

 

NGLs

 

 

Equivalent

 

 

(MBbls)

 

 

(MMcf)

 

 

(MBbls)

 

 

(MMcfe)

 

Proved developed and undeveloped reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning of year

 

90,945

 

 

 

461,526

 

 

 

43,395

 

 

 

1,267,571

 

Extensions and discoveries

 

297

 

 

 

288

 

 

 

42

 

 

 

2,320

 

Production

 

(3,883

)

 

 

(44,776

)

 

 

(2,283

)

 

 

(81,773

)

Sale of minerals in place

 

(3,228

)

 

 

(15,227

)

 

 

(123

)

 

 

(35,328

)

Revision of previous estimates

 

(18,390

)

 

 

(30,795

)

 

 

(15,847

)

 

 

(236,225

)

End of year

 

65,741

 

 

 

371,016

 

 

 

25,184

 

 

 

916,565

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning of year

 

50,817

 

 

 

311,147

 

 

 

30,315

 

 

 

797,936

 

End of year

 

45,536

 

 

 

280,035

 

 

 

18,923

 

 

 

666,786

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning of year

 

40,128

 

 

 

150,379

 

 

 

13,080

 

 

 

469,635

 

End of year

 

20,205

 

 

 

90,981

 

 

 

6,261

 

 

 

249,779

 

 

 

Year Ended December 31, 2015

 

 

Oil

 

 

Gas

 

 

NGLs

 

 

Equivalent

 

 

(MBbls)

 

 

(MMcf)

 

 

(MBbls)

 

 

(MMcfe)

 

Proved developed and undeveloped reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning of year

 

100,258

 

 

 

727,216

 

 

 

59,034

 

 

 

1,682,960

 

Extensions and discoveries

 

2,319

 

 

 

8,686

 

 

 

558

 

 

 

25,950

 

Purchase of minerals in place

 

10,132

 

 

 

34,128

 

 

 

367

 

 

 

97,122

 

Production

 

(4,087

)

 

 

(50,875

)

 

 

(2,820

)

 

 

(92,315

)

Sale of minerals in place

 

(380

)

 

 

(13,731

)

 

 

(758

)

 

 

(20,559

)

Revision of previous estimates

 

(17,297

)

 

 

(243,898

)

 

 

(12,986

)

 

 

(425,587

)

End of year

 

90,945

 

 

 

461,526

 

 

 

43,395

 

 

 

1,267,571

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning of year

 

54,723

 

 

 

417,247

 

 

 

37,260

 

 

 

969,141

 

End of year

 

50,817

 

 

 

311,147

 

 

 

30,315

 

 

 

797,936

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning of year

 

45,535

 

 

 

309,969

 

 

 

21,774

 

 

 

713,819

 

End of year

 

40,128

 

 

 

150,379

 

 

 

13,080

 

 

 

469,635

 

F-44


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

 

 

Year Ended December 31, 2014

 

 

Oil

 

 

Gas

 

 

NGLs

 

 

Equivalent

 

 

(MBbls)

 

 

(MMcf)

 

 

(MBbls)

 

 

(MMcfe)

 

Proved developed and undeveloped reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning of year

 

39,635

 

 

 

737,908

 

 

 

35,794

 

 

 

1,190,484

 

Extensions and discoveries

 

849

 

 

 

12,783

 

 

 

711

 

 

 

22,145

 

Purchase of minerals in place

 

69,095

 

 

 

13,036

 

 

 

22,351

 

 

 

561,713

 

Production

 

(3,135

)

 

 

(48,721

)

 

 

(2,498

)

 

 

(82,520

)

Revision of previous estimates

 

(6,186

)

 

 

12,210

 

 

 

2,676

 

 

 

(8,862

)

End of year

 

100,258

 

 

 

727,216

 

 

 

59,034

 

 

 

1,682,960

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning of year

 

22,429

 

 

 

427,983

 

 

 

17,637

 

 

 

668,381

 

End of year

 

54,723

 

 

 

417,247

 

 

 

37,260

 

 

 

969,141

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning of year

 

17,206

 

 

 

309,925

 

 

 

18,157

 

 

 

522,103

 

End of year

 

45,535

 

 

 

309,969

 

 

 

21,774

 

 

 

713,819

 

 

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

 

The 351.0 Bcfe reduction in reserves for the year ended December 31, 2016 is primarily due to a 148.3 Bcfe downward pricing revision and a 87.9 Bcfe downward revision due to updated well performance data. We divested 35.3 Bcfe during the year ended December 31, 2016. Proved undeveloped reserves decreased primarily due to downward pricing during the year ended December 31, 2016.

 

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.

 

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.

See Note 4 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.

The standardized measure of discounted future net cash flows is as follows:

 

Years Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

 

(In thousands)

 

Future cash inflows

$

3,666,731

 

 

$

5,952,935

 

 

$

14,190,450

 

Future production costs

 

(2,384,195

)

 

 

(3,194,577

)

 

 

(4,821,051

)

Future development costs

 

(440,496

)

 

 

(808,512

)

 

 

(1,455,926

)

Future income tax expense (1)

 

 

 

 

 

 

 

(119,675

)

Future net cash flows for estimated timing of cash flows

 

842,040

 

 

 

1,949,846

 

 

 

7,793,798

 

10% annual discount for estimated timing of cash flows

 

(446,199

)

 

 

(1,360,292

)

 

 

(4,881,811

)

Standardized measure of discounted future net cash flows

$

395,841

 

 

$

589,554

 

 

$

2,911,987

 

 

 

(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, 2016, 2015 and 2014.  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.

F-45


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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, 2016:

 

Years Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

 

(In thousands)

 

Beginning of year

$

589,554

 

 

$

2,911,987

 

 

$

1,718,204

 

Sale of oil and natural gas produced, net of production costs

 

(107,357

)

 

 

(128,382

)

 

 

(354,932

)

Purchase of minerals in place

 

 

 

 

75,998

 

 

 

1,489,477

 

Sale of minerals in place

 

(28,277

)

 

 

(45,100

)

 

 

 

Extensions and discoveries

 

2,016

 

 

 

18,582

 

 

 

44,843

 

Changes in income taxes, net

 

 

 

 

63,180

 

 

 

(63,180

)

Changes in prices and costs

 

(404,870

)

 

 

(2,764,481

)

 

 

(170,682

)

Previously estimated development costs incurred

 

89,748

 

 

 

322,446

 

 

 

275,078

 

Net changes in future development costs

 

254,043

 

 

 

448,089

 

 

 

(133,098

)

Revisions of previous quantities

 

14,414

 

 

 

(344,775

)

 

 

(48,087

)

Accretion of discount

 

58,956

 

 

 

297,517

 

 

 

171,820

 

Change in production rates and other

 

(72,386

)

 

 

(265,507

)

 

 

(17,456

)

End of year

$

395,841

 

 

$

589,554

 

 

$

2,911,987

 

 

Note. 18 Subsequent Events

Hedge Monetization

For additional information, see Note 6 and Note 9.

Chapter 11 Bankruptcy Filings

For additional information, see Note 2 and Note 9.

Entry into a Material Definitive Agreement

On January 13, 2017, the Partnership entered into a Plan Support Agreement with lenders holding 100% of the loans under the Credit Agreement, by and among OLLC, the Partnership, and Wells Fargo Bank, National Association as administrative agent. See Note 2 and Note 9 for additional information.

On January 13, 2017, the Partnership entered into the third amendment to limited waiver, which extended the outside date of the limited waiver period under the limited waiver from January 13, 2017 to January 16, 2017. See Note 2 and 9 for additional information.

Notice of Delisting

For additional information, see Note 2.

 

 

F-46


 

Exhibit Index

 

Exhibit
Number

 

 

 

Description

 

 

 

2.1##

 

 

Purchase and Sale Agreement, dated as of March 25, 2014, between Alta Mesa Eagle, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on March 25, 2014).

 

 

 

2.2##

 

 

Purchase and Sale Agreement, dated as of May 2, 2014, among Merit Management Partners I, L.P., Merit Energy Partners III, L.P., Merit Pipeline Company, LLC and Merit Energy Company, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on May 5, 2014).

 

 

 

 

 

2.3##

 

 

Purchase and Sale Agreement, dated as of November 3, 2015, by and between SP Beta Holdings, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on November 5, 2015).

 

 

 

2.4##

 

 

Purchase and Sale Agreement, dated as of April 27, 2016, among Memorial Production Partners LP, Memorial Resources Development Corp., Memorial Production Partners GP LLC, Memorial Production Operating LLC, Beta Operating Company, LLC and MEMP Services LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on May 2, 2016).

 

 

 

 

 

2.5##

 

 

Joint Plan of Reorganization of Memorial Production Partners LP, et al. under Chapter 11 of the Bankruptcy Code, dated as of January 16, 2017 (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on January 17, 2017).

 

 

 

 

 

3.1

 

 

Certificate of Limited Partnership of Memorial Production Partners LP (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-1 (File No. 333-175090) filed on June 23, 2011).

 

 

 

3.2

 

 

First Amended and Restated Agreement of Limited Partnership of Memorial Production Partners LP (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011).

 

 

 

3.3

 

 

Second Amended and Restated Agreement of Limited Partnership of Memorial Production Partners LP (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K (File No. 001-35364) filed June 1, 2016).

 

 

 

3.4

 

 

Certificate of Formation of Memorial Production Partners GP LLC (incorporated by reference to Exhibit 3.4 to Registration Statement on Form S-1 (File No. 333-175090) filed on June 23, 2011).

 

 

 

3.5

 

 

Third Amended and Restated Limited Liability Company Agreement of Memorial Production Partners GP LLC (incorporated by reference to Exhibit 3.4 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on August 6, 2014).

 

 

 

3.6

 

 

Fourth Amended and Restated Limited Liability Company Agreement of Memorial Production Partners GP LLC (incorporated by reference to Exhibit 3.2 to Current Report on Form 8-K (File No. 001-35364) filed June 1, 2016).

 

 

 

 

 

4.1#

 

 

Form of Restricted Unit Agreement under the Memorial Production Partners GP LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 4.6 to Registration Statement on Form S-8 (File No. 333-178493) filed on December 14, 2011).

 

 

 

4.2#

 

 

Form of Phantom Unit Agreement under the Memorial Production Partners GP LLC Long-Term Incentive Plan. (incorporated by reference to Exhibit 4.2 to Annual Report on Form 10-K (File No. 001-35364) filed on February 24, 2016.

 

 

 

 

 

4.3

 

 

Indenture, dated April 17, 2013, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K (File No. 001-35364) filed on April 17, 2013).

 

 

 

4.4

 

 

First Supplemental Indenture, dated as of October 7, 2013, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on November 7, 2013).

1


 

Exhibit
Number

 

 

 

Description

 

 

 

 

 

4.5

 

 

Second Supplemental Indenture, dated as of December 30, 2015, by and among San Pedro Bay Pipeline Company, Memorial Production Partners LP, Memorial Production Finance Corporation, the other subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.5 to Annual Report on Form 10-K (File No. 001-35364) filed on February 24, 2016).

 

 

 

4.6

 

 

Indenture, dated July 17, 2014, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K (File No. 001-35364) filed on July 17, 2014).

 

 

 

 

 

4.7

 

 

First Supplemental Indenture, dated as of December 30, 2015, by and among San Pedro Bay Pipeline Company, Memorial Production Partners LP, Memorial Production Finance Corporation, the other subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.7 to Annual Report on Form 10-K (File No. 001-35364) filed on February 24, 2016).

 

 

 

 

 

4.8

 

 

Instrument of Resignation, Appointment and Acceptance, dated as of June 24, 2016, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, Wilmington Trust, National Association, as successor trustee, and U.S. Bank National Association, as resigning trustee (incorporated by reference to Exhibit 4.3 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on August 3, 2016).

 

 

 

 

 

4.9

 

 

Instrument of Resignation, Appointment and Acceptance, dated as of June 24, 2016, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, Wilmington Trust, National Association, as successor trustee, and U.S. Bank National Association, as resigning trustee (incorporated by reference to Exhibit 4.4 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on August 3, 2016).

 

 

 

 

 

4.10

 

 

Second Supplemental Indenture, dated as of July 20, 2016, by and among Memorial Production Partners GP LLC, MEMP Services LLC, Beta Operating Company, LLC, Memorial Production Partners LP, Memorial Production Finance Corporation, the other subsidiary guarantors named therein and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.5 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on August 3, 2016).

 

 

 

 

 

4.11

 

 

Third Supplemental Indenture, dated as of July 20, 2016, by and among Memorial Production Partners GP LLC, MEMP Services LLC, Beta Operating Company, LLC, Memorial Production Partners LP, Memorial Production Finance Corporation, the other subsidiary guarantors named therein and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.6 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on August 3, 2016).

 

 

 

 

 

10.1

 

 

Omnibus Agreement, dated as of December 14, 2011, by and among Memorial Production Partners LP, Memorial Production Partners GP LLC and Memorial Resource Development LLC (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011).

 

 

 

 

 

10.2

 

 

Equity Distribution Agreement, dated May 25, 2016, among Memorial Production Partners LP, Memorial Production Partners GP LLC, Memorial Production Operating LLC and UBS Securities LLC and FBR Capital Markets & Co (incorporated by reference to Exhibit 1.1 to Current Report on Form 8-K (File No. 001-35364) filed on May 25, 2016).

 

 

 

 

 

10.3#

 

 

Memorial Production Partners GP LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.7 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011).

 

 

 

 

 

10.4#

 

 

Form of Change of Control Agreement (incorporated by reference to Exhibit 10.2 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on May 4, 2016).

 

 

 

 

 

*10.5#

 

 

Form of Key Employee Retention Bonus Agreement for Senior Management

 

 

 

 

 

*10.6#

 

 

Form of Key Employee Retention Bonus Agreement

 

 

 

 

 

*10.7#

 

 

Memorial Production Partners LP Key Employee Incentive Plan

2


 

Exhibit
Number

 

 

 

Description

 

 

 

 

 

10.8

 

 

Credit Agreement, dated as of December 14, 2011, among Memorial Production Operating LLC, as borrower, Memorial Production Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent for the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent for the lenders party thereto, BNP Paribas, Citibank, N.A. and Comerica Bank, as co-documentation agents for the lenders party thereto, and the other lenders party thereto (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011), as amended by First Amendment to Credit Agreement, dated as of April 30, 2012 (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on May 15, 2012), as further amended by Second Amendment to Credit Agreement, dated as of September 18, 2012 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on September 19, 2012), as further amended by Third Amendment to Credit Agreement, dated as of December 3, 2012 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 4, 2012), as further amended by Fourth Amendment to Credit Agreement and First Amendment to Guaranty Agreement, dated as of March 8, 2013 (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q (File No. 001-35364) filed on May 10, 2013), as further amended by Fifth Amendment to Credit Agreement, dated as of March 19, 2013 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on March 21, 2013), as further amended by Sixth Amendment to Credit Agreement, dated as of September 26, 2013 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on October 1, 2013), as further amended by Seventh Amendment to Credit Agreement, dated as of June 13, 2014 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on June 19, 2014), as further amended by Eighth Amendment to Credit Agreement, dated as of October 10, 2014 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on October 14, 2014), as further amended by Ninth Amendment to Credit Agreement, dated as of December 17, 2014 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 18, 2014) as further amended by Tenth Amendment to Credit Agreement, dated as of April 14, 2016 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on April 14, 2016) and as further amended by Eleventh Amendment to Credit Agreement, dated as of October 28, 2016 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on November 1, 2016).

 

 

 

 

 

10.9

 

 

Limited Waiver and Twelfth Amendment to Credit Agreement, dated as of November 1, 2016, by and among Memorial Production Partners LP, Memorial Production Operating LLC, the guarantors party thereto, Wells Fargo Bank, National Association, as administrative agent for the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent for the lenders party thereto, Royal Bank of Canada, Citizens Bank, N.A., MUFG Union Bank, N.A. f/k/a Union Bank, N.A. and Comerica Bank, as co-documentation agents for the lenders party thereto, and the other lenders party thereto (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K (File No. 001-35364) filed on November 1, 2016).

 

 

 

 

 

10.10

 

 

First Amendment to Limited Waiver, dated as of November 30, 2016, among Memorial Production Operating LLC, Memorial Production Partners LP, certain other guarantors and lenders and Wells Fargo Bank, National Association, as administrative agent for the lenders (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 1, 2016).

 

 

 

 

 

10.11

 

 

Forbearance dated as of November 30, 2016, among Memorial Production Partners LP, Memorial Production Finance Corporation, certain guarantors party thereto, and the 2021 Holders (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K (File No. 001-35364) filed on December 1, 2016).

 

 

 

 

 

10.12

 

 

 

Forbearance dated as of November 30, 2016, among Memorial Production Partners LP, Memorial Production Finance Corporation, certain guarantors party thereto, and the 2022 Holders (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K (File No. 001-35364) filed on December 1, 2016).

 

 

 

 

 

10.13

 

 

First Amendment to Forbearance Agreement, dated as of December 7, 2016, among Memorial Production Partners LP (the “Partnership”), Memorial Production Finance Corporation, certain guarantors party thereto, and certain holders of the Partnership’s 7.625% Senior Notes due 2021(incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 8, 2016).

 

 

 

 

 

10.14

 

 

First Amendment to Forbearance Agreement, dated as of December 7, 2016, among Memorial Production Partners LP (the “Partnership”), Memorial Production Finance Corporation, certain guarantors party thereto, and certain holders of the Partnership’s 6.875% Senior Notes due 2022 (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K (File No. 001-35364) filed on December 8, 2016).

3


 

Exhibit
Number

 

 

 

Description

 

 

 

 

 

10.15

 

 

Second Amendment to Limited Waiver, dated as of December 16, 2016, among Memorial Production Operating LLC, Memorial Production Partners LP, certain other guarantors and lenders and Wells Fargo Bank, National Association, as administrative agent for the lenders (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 19, 2016).

 

 

 

 

 

10.16

 

 

Third Amendment to Limited Waiver, dated as of January 13, 2017, among Memorial Production Operating LLC, Memorial Production Partners LP, certain other guarantors and lenders and Wells Fargo Bank, National Association, as administrative agent for the lenders (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K (File No. 001-35364) filed on January 17, 2017).

 

 

 

 

 

10.17

 

 

Plan Support Agreement, dated as of December 22, 2016, among Memorial Production Partners LP (the “Partnership”) and its subsidiaries party thereto and certain holders of the Partnership’s 7.625% Senior Notes due 2021 and the Partnership’s 6.875% Senior Notes due 2022 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 23, 2016).

 

 

 

 

 

10.18

 

 

Plan Support Agreement, dated as of January 13, 2017, among Memorial Production Partners LP and its subsidiaries party thereto and the banks party thereto (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on January 17, 2017).

 

 

 

 

 

10.19#

 

 

Amendment to Plan Support Agreement, dated as of January 12, 2017, among Memorial Production Partners LP (the “Partnership”) and its subsidiaries party thereto and certain holders of the Partnership’s 7.625% Senior Notes due 2021 and the Partnership’s 6.875% Senior Notes due 2022 (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K (File No. 001-35364) filed on January 17, 2017).

 

 

 

 

 

10.20

 

 

Form of Director Indemnification Agreement (incorporated by reference to Exhibit 10.8 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011).

 

 

 

 

 

21.1*

 

 

List of Subsidiaries of Memorial Production Partners LP.

 

 

 

23.1*

 

 

Consent of Ryder Scott Company, L.P.

 

 

 

31.1*

 

 

Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934

 

 

 

31.2*

 

 

Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934

 

 

 

32.1*

 

 

Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

99.1*

 

 

Report of Ryder Scott Company, L.P.

 

 

 

101.CAL*

 

 

XBRL Calculation Linkbase Document

 

 

 

101.DEF*

 

 

XBRL Definition Linkbase Document

 

 

 

101.INS*

 

 

XBRL Instance Document

 

 

 

101.LAB*

 

 

XBRL Labels Linkbase Document

 

 

 

101.PRE*

 

 

XBRL Presentation Linkbase Document

 

 

 

101.SCH*

 

 

XBRL Schema Document

 

*

Filed or furnished as an exhibit to this Annual Report on Form 10-K.

#

Management contract or compensatory plan or arrangement.

##

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.

 

 

4