Amplify Energy Corp.
Memorial Production Partners LP (Form: 10-K, Received: 03/10/2017 16:56:46)

 

 

 

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 CO 2 ;

 

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


P ART I

I TEM 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