Attached files

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EX-10.2 - EX-10.2 - FORM OF CHANGE OF CONTROL AGREEMENT - Amplify Energy Corpmemp-ex102_612.htm
EX-31.2 - EX-31.2 - CERTIFICATION OF CFO - Amplify Energy Corpmemp-ex312_9.htm
EX-31.1 - EX-31.1 - CERTIFICATION OF CEO - Amplify Energy Corpmemp-ex311_6.htm
EX-32.1 - EX-32.1 - SECTION 906 CERTIFICATION - Amplify Energy Corpmemp-ex321_7.htm

 

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10–Q

 

þ

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

For the quarterly period ended March 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 1800, Houston, TX

 

77002

(Address of principal executive offices)

 

(Zip Code)

Registrant’s telephone number, including area code: (713) 588-8300

 

 

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

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

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

 

Large accelerated filer  þ

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  þ

As of April 30, 2016, the registrant had 82,899,509 common units and 86,797 general partner units outstanding.

 

 

 


MemORIAL PRoducTION PARTNERS LP

Table of Contents

 

 

 

 

 

Page

 

 

 

 

 

 

 

 

 

 

 

 

Glossary of Oil and Natural Gas Terms

 

1

 

 

Names of Entities

 

4

 

 

Cautionary Note Regarding Forward-Looking Statements

 

5

 

 

PART I—FINANCIAL INFORMATION

 

 

Item 1.

 

Financial Statements

 

 

 

 

Unaudited Condensed Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015

 

7

 

 

Unaudited Condensed Statements of Consolidated and Combined Operations for the Three Months Ended March 31, 2016 and 2015

 

8

 

 

Unaudited Condensed Statements of Consolidated and Combined Cash Flows for the Three Months Ended March 31, 2016 and 2015

 

9

 

 

Unaudited Condensed Statements of Consolidated Equity for the Three Months Ended March 31, 2016

 

10

 

 

Notes to Unaudited Condensed Consolidated and Combined Financial Statements

 

11

 

 

Note 1 – Organization and Basis of Presentation

 

11

 

 

Note 2 – Summary of Significant Accounting Policies

 

12

 

 

Note 3 – Acquisitions and Divestitures

 

14

 

 

Note 4 – Fair Value Measurements of Financial Instruments

 

14

 

 

Note 5 – Risk Management and Derivative Instruments

 

16

 

 

Note 6 – Asset Retirement Obligations

 

19

 

 

Note 7 – Long Term Debt

 

19

 

 

Note 8 – Equity & Distributions

 

22

 

 

Note 9 – Earnings per Unit

 

23

 

 

Note 10 – Unit-Based Awards

 

23

 

 

Note 11 – Related Party Transactions

 

24

 

 

Note 12 – Commitments and Contingencies

 

25

 

 

Note 13 – Subsequent Events

 

26

 

 

 

 

 

Item 2.

 

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

 

27

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk

 

36

Item 4.

 

Controls and Procedures

 

37

 

 

PART II—OTHER INFORMATION

 

 

Item 1.

 

Legal Proceedings

 

38

Item 1A.

 

Risk Factors

 

38

Item 2.

 

Unregistered Sales of Equity Securities and Use of Proceeds

 

38

Item 3.

 

Defaults Upon Senior Securities

 

38

Item 4.

 

Mine Safety Disclosures

 

38

Item 5.

 

Other Information

 

38

Item 6.

 

Exhibits

 

39

 

 

 

Signatures

 

40

 

 

 

i


GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

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

Bbl/d: One Bbl per day.

Bcfe: One billion cubic feet of natural gas equivalent.

BOEM: Bureau of Ocean Energy Management.

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

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

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

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

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

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

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

ICE: Inter-Continental Exchange.

MBbl: One thousand Bbls.

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

MBoe/d: One thousand Boe per day.

MBtu: One thousand Btu.

Mcf: One thousand cubic feet of natural gas.

Mcf/d: One Mcf per day.

MMBtu: One million British thermal units.

1


MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

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

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

NYMEX: New York Mercantile Exchange.

Oil: Oil and condensate.

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

OPIS: Oil Price Information Service.

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

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

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

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

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

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

2


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

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

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

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

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.

 

 

 

3


NAMES OF ENTITIES

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

 

·

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

 

·

“our general partner” and “MEMP GP” refer to Memorial Production Partners GP LLC, our general partner;

 

·

“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;

 

·

“Memorial Resource” refers collectively to Memorial Resource Development Corp. and its subsidiaries other than the Partnership;

 

·

“the previous owners” for accounting and financial reporting purposes refers to certain oil and gas properties primarily located in the Joaquin Field in Shelby and Panola counties in East Texas and in West Louisiana acquired from Memorial Resource in February 2015 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.;

 

·

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

 

·

“NGP” refers to Natural Gas Partners. The Funds, which are three of the private equity funds managed by NGP, collectively control MRD Holdco.

 

 

 

4


CAUTIONARY NOTE REGARDING FORWARD–LOOKING STATEMENTS

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

 

·

business strategies;

 

·

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;

 

·

general and administrative expenses;

 

·

future operating results;

 

·

cash flows and liquidity;

 

·

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.

5


These types of statements, other than statements of historical fact included in this report, are forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “outlook,” “continue,” the negative of such terms or other comparable terminology. These statements discuss future expectations, contain projections of results of operations or of financial condition or include other “forward-looking” information. These forward-looking statements involve risks and uncertainties. Important factors that could cause our actual results or financial condition to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

 

·

our ability to generate sufficient cash to pay the current quarterly distribution or any other amount on our common units;

 

·

risks related to our level of indebtedness, including our ability to satisfy our debt obligations;

 

·

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

 

·

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;

 

·

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 interests in properties in which we also own an interest; and

 

·

risks related to potential acquisitions, including our ability to make acquisitions on favorable terms or to integrate acquired properties.

The forward-looking statements contained in this report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events or circumstances described in any forward-looking statement will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in “Part I—Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2015 (“2015 Form 10-K”) and “Part II—Item 1A. Risk Factors” appearing within this report and elsewhere in this report. All forward-looking statements speak only as of the date of this report. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

 

 

6


PART I—FINANCIAL INFORMATION

 

ITEM 1.

FINANCIAL STATEMENTS.

MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding units)

 

 

March 31,

 

December 31,

 

 

2016

 

2015

 

ASSETS

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

Cash and cash equivalents

$

836

 

$

599

 

Accounts receivable

 

45,290

 

 

60,239

 

Short-term derivative instruments

 

259,854

 

 

272,320

 

Prepaid expenses and other current assets

 

4,839

 

 

7,028

 

Total current assets

 

310,819

 

 

340,186

 

Property and equipment, at cost:

 

 

 

 

 

 

Oil and natural gas properties, successful efforts method

 

3,639,835

 

 

3,616,325

 

Support equipment and facilities

 

206,147

 

 

205,876

 

Other

 

2,491

 

 

2,671

 

Accumulated depreciation, depletion and impairment

 

(1,931,091

)

 

(1,878,549

)

Property and equipment, net

 

1,917,382

 

 

1,946,323

 

Long-term derivative instruments

 

442,616

 

 

461,810

 

Restricted investments

 

154,766

 

 

152,631

 

Other long-term assets

 

4,519

 

 

5,053

 

Total assets

$

2,830,102

 

$

2,906,003

 

 

 

 

 

 

 

 

LIABILITIES AND EQUITY

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

Accounts payable

$

6,863

 

$

8,792

 

Accounts payable - affiliates

 

5,137

 

 

3,339

 

Revenues payable

 

25,427

 

 

25,504

 

Accrued liabilities (Note 2)

 

61,744

 

 

52,923

 

Short-term derivative instruments

 

2,098

 

 

2,850

 

Total current liabilities

 

101,269

 

 

93,408

 

Long-term debt (Note 7)

 

1,957,984

 

 

2,000,579

 

Asset retirement obligations

 

164,964

 

 

162,989

 

Long-term derivative instruments

 

2,161

 

 

1,441

 

Deferred tax liabilities

 

2,158

 

 

2,094

 

Total liabilities

 

2,228,536

 

 

2,260,511

 

Commitments and contingencies (Note 12)

 

 

 

 

 

 

Equity:

 

 

 

 

 

 

Partners' equity:

 

 

 

 

 

 

Common units (82,925,302 units outstanding at March 31, 2016 and 82,906,400 units

   outstanding at December 31, 2015)

 

600,767

 

 

644,644

 

General partner (86,797 units outstanding at March 31, 2016 and December 31, 2015)

 

799

 

 

848

 

Total partners' equity

 

601,566

 

 

645,492

 

Total liabilities and equity

$

2,830,102

 

$

2,906,003

 

 

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

 

 

 

7


MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS

(In thousands, except per unit amounts)

  

 

 

For the Three Months Ended

 

 

 

March 31,

 

 

 

2016

 

 

2015

 

Revenues:

 

 

 

 

 

 

 

 

Oil & natural gas sales

 

$

60,623

 

 

$

91,949

 

Other revenues

 

 

243

 

 

 

869

 

Total revenues

 

 

60,866

 

 

 

92,818

 

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

 

Lease operating

 

 

35,696

 

 

 

40,478

 

Gathering, processing and transportation

 

 

9,209

 

 

 

8,666

 

Exploration

 

 

122

 

 

 

90

 

Taxes other than income

 

 

4,008

 

 

 

6,655

 

Depreciation, depletion, and amortization

 

 

44,429

 

 

 

51,266

 

Impairment of proved oil and natural gas properties

 

 

8,342

 

 

 

251,347

 

General and administrative

 

 

13,524

 

 

 

14,511

 

Accretion of asset retirement obligations

 

 

2,707

 

 

 

1,634

 

(Gain) loss on commodity derivative instruments

 

 

(51,745

)

 

 

(145,459

)

(Gain) loss on sale of properties

 

 

(96

)

 

 

 

Other, net

 

 

119

 

 

 

 

Total costs and expenses

 

 

66,315

 

 

 

229,188

 

Operating income (loss)

 

 

(5,449

)

 

 

(136,370

)

Other income (expense):

 

 

 

 

 

 

 

 

Interest expense, net

 

 

(32,552

)

 

 

(28,818

)

Other income (expense)

 

 

 

 

 

160

 

Total other income (expense)

 

 

(32,552

)

 

 

(28,658

)

Income (loss) before income taxes

 

 

(38,001

)

 

 

(165,028

)

Income tax benefit (expense)

 

 

(96

)

 

 

2,370

 

Net income (loss)

 

 

(38,097

)

 

 

(162,658

)

Net income (loss) attributable to noncontrolling interest

 

 

 

 

 

159

 

Net income (loss) attributable to Memorial Production Partners LP

 

$

(38,097

)

 

$

(162,817

)

 

 

 

 

 

 

 

 

 

Limited partners' interest in net income (loss):

 

 

 

 

 

 

 

 

Net income (loss) attributable to Memorial Production Partners LP

 

$

(38,097

)

 

$

(162,817

)

Net (income) loss allocated to previous owners

 

 

 

 

 

2,268

 

Net (income) loss allocated to general partner

 

 

40

 

 

 

138

 

Net (income) loss allocated to NGP IDRs

 

 

 

 

 

(28

)

Limited partners' interest in net income (loss)

 

$

(38,057

)

 

$

(160,439

)

 

 

 

 

 

 

 

 

 

Earnings per unit: (Note 9)

 

 

 

 

 

 

 

 

Basic and diluted earnings per unit

 

$

(0.46

)

 

$

(1.90

)

Weighted average limited partner units outstanding:

 

 

 

 

 

 

 

 

Basic and diluted

 

 

82,935

 

 

 

84,339

 

 

 

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

 

 

 

 

8


MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS

(In thousands)

 

 

 

For the Three Months Ended

 

 

 

March 31,

 

 

 

2016

 

 

2015

 

Cash flows from operating activities:

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(38,097

)

 

$

(162,658

)

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

 

 

 

 

 

 

 

 

Depreciation, depletion, and amortization

 

 

44,429

 

 

 

51,266

 

Impairment of proved oil and natural gas properties

 

 

8,342

 

 

 

251,347

 

(Gain) loss on derivative instruments

 

 

(48,063

)

 

 

(143,018

)

Cash settlements (paid) received on expired derivative instruments

 

 

79,691

 

 

 

59,236

 

Cash settlements on terminated commodity derivatives

 

 

 

 

 

27,063

 

Premiums paid for commodity derivatives

 

 

 

 

 

(27,063

)

Deferred income tax expense (benefit)

 

 

65

 

 

 

(2,370

)

Amortization of deferred financing costs

 

 

1,202

 

 

 

1,860

 

Accretion of senior notes net discount

 

 

605

 

 

 

599

 

Accretion of asset retirement obligations

 

 

2,707

 

 

 

1,634

 

Unit-based compensation (see Note 10)

 

 

2,568

 

 

 

2,341

 

Settlement of asset retirement obligations

 

 

(615

)

 

 

 

Gain on sale of properties

 

 

(96

)

 

 

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

Accounts receivable

 

 

14,977

 

 

 

13,000

 

Prepaid expenses and other assets

 

 

2,190

 

 

 

(5,684

)

Payables and accrued liabilities

 

 

7,058

 

 

 

4,410

 

Other

 

 

43

 

 

 

 

Net cash provided by operating activities

 

 

77,006

 

 

 

71,963

 

Cash flows from investing activities:

 

 

 

 

 

 

 

 

Acquisitions of oil and natural gas properties

 

 

 

 

 

(3,305

)

Additions to oil and gas properties

 

 

(22,537

)

 

 

(74,375

)

Additions to other property and equipment

 

 

(95

)

 

 

 

Additions to restricted investments

 

 

(2,136

)

 

 

(1,426

)

Proceeds from the sale of oil and natural gas properties

 

 

325

 

 

 

 

Net cash used in investing activities

 

 

(24,443

)

 

 

(79,106

)

Cash flows from financing activities:

 

 

 

 

 

 

 

 

Advances on revolving credit facilities

 

 

28,000

 

 

 

166,000

 

Payments on revolving credit facilities

 

 

(72,000

)

 

 

(5,000

)

Deferred financing costs

 

 

(18

)

 

 

(10

)

Repurchase of senior notes

 

 

 

 

 

(2,914

)

Capital contributions from previous owners

 

 

 

 

 

1,912

 

Contributions related to sale of assets to NGP affiliate

 

 

26

 

 

 

 

Distributions to partners

 

 

(8,304

)

 

 

(46,315

)

Distribution to Memorial Resource (see Note 1)

 

 

 

 

 

(78,000

)

Restricted units returned to plan

 

 

(30

)

 

 

(7

)

Repurchases under unit repurchase program

 

 

 

 

 

(28,420

)

Net cash (used in) provided by financing activities

 

 

(52,326

)

 

 

7,246

 

Net change in cash and cash equivalents

 

 

237

 

 

 

103

 

Cash and cash equivalents, beginning of period

 

 

599

 

 

 

970

 

Cash and cash equivalents, end of period

 

$

836

 

 

$

1,073

 

 

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

 

 

 

9


 

MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

(In thousands)

  

 

Partner's Equity

 

 

 

 

 

 

Limited Partners

 

 

General

 

 

 

 

 

 

Common

 

 

Partner

 

 

Total

 

Balance, December 31, 2015

$

644,644

 

 

$

848

 

 

$

645,492

 

Net income (loss)

 

(38,057

)

 

 

(40

)

 

 

(38,097

)

Distributions

 

(8,295

)

 

 

(9

)

 

 

(8,304

)

Amortization of equity-based awards

 

2,492

 

 

 

 

 

 

2,492

 

Restricted units repurchased and other

 

(17

)

 

 

 

 

 

(17

)

Balance, March 31, 2016

$

600,767

 

 

$

799

 

 

$

601,566

 

 

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

 

 

 

10


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 1. Organization and Basis of Presentation

General

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

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

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

The Partnership is owned 99.9% by its limited partners and 0.1% by MEMP GP, which is a wholly-owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership’s operations and activities. Memorial Resource provides management, administrative and operations personnel to us and our general partner under an omnibus agreement (see Note 11). The Funds, which are three of the private equity funds managed by NGP, collectively control MRD Holdco. The Funds collectively indirectly own 50% of our incentive distribution rights (“IDRs”). The remaining IDRs are owned by our general partner.

Subsequent Event.  On April 27, 2016, we entered into an agreement to acquire MEMP GP from Memorial Resource (“MEMP GP Acquisition”).  In addition, on April 27, 2016, we entered into an agreement to acquire the 50% ownership of the IDRs of the Partnership owned by NGP (“NGP Acquisition”).  See Note 13, for additional information regarding both acquisitions.

Previous Owners

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

Basis of Presentation

Our consolidated results of operations are presented together with the combined results of operations pertaining to the previous owners. The combined financial statements of the previous owners were derived from their historical accounting records and reflect their historical financial position, results of operations and cash flows. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation.

11


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Our results of operations for the three months ended March 31, 2016 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”).

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

Use of Estimates

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

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

 

Note 2. Summary of Significant Accounting Policies

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

Accrued Liabilities

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

 

 

March 31,

 

 

December 31,

 

 

2016

 

 

2015

 

Accrued capital expenditures

$

9,985

 

 

$

8,110

 

Accrued interest payable

 

27,992

 

 

 

23,192

 

Accrued lease operating expense

 

16,919

 

 

 

16,843

 

Accrued ad valorem taxes

 

2,597

 

 

 

1,426

 

Accrued general and administrative expenses

 

2,882

 

 

 

1,961

 

Environmental liability

 

88

 

 

 

216

 

Asset retirement obligation

 

1,175

 

 

 

1,175

 

Other

 

106

 

 

 

 

 

$

61,744

 

 

$

52,923

 

Supplemental Cash Flows

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

 

 

 

For the Three Months Ended

 

 

 

March 31,

 

 

 

2016

 

 

2015

 

Supplemental cash flows:

 

 

 

 

 

 

 

 

Cash paid for interest, net of amounts capitalized

 

 

22,793

 

 

 

21,298

 

Noncash investing and financing activities:

 

 

 

 

 

 

 

 

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

 

 

1,875

 

 

 

(1,450

)

Asset retirement obligation removal related to divestitures

 

 

(451

)

 

 

 

Assumptions of asset retirement obligations related to properties acquired

 

 

 

 

 

2,266

 

 


12


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

New Accounting Pronouncements

 

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

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

 

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

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

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.

 

 

13


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 3. Acquisitions and Divestitures

Related Party Acquisitions

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

Acquisition-related Costs

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

 

For the Three Months Ended

 

March 31,

 

2016

 

 

2015

 

$

86

 

 

$

1,299

 

2015 Acquisitions

 2015 Beta Acquisition. On November 3, 2015, we closed a transaction to acquire the noncontrolling interest in San Pedro Bay Pipeline Company (“SPBPC”) and the remaining interests in our oil and gas properties offshore Southern California (the “Beta Properties”) from a third party (the “2015 Beta Acquisition”), which was discussed in our 2015 Form 10-K.

 

Pro forma Information. The following unaudited pro forma combined results of operations are provided for the three months ended March 31, 2015 as though the 2015 Beta Acquisition had been completed on January 1, 2014. The unaudited pro forma financial information was derived from the historical consolidated and combined statements of operations of the Partnership and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired, (iii) accretion expense associated with asset retirement obligations recorded and (iv) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.    

 

 

 

For the Three Months Ended

 

 

 

March 31,

 

 

 

2015

 

 

 

(In thousands, except per unit amounts)

 

Revenues

 

$

99,081

 

Net income (loss)

 

 

(162,306

)

Basic and diluted earnings per unit

 

 

(1.90

)

 

Divestitures

There were no material divestitures during the three months ended March 31, 2016 and 2015, respectively.

 

 

Note 4. Fair Value Measurements of Financial Instruments

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

The carrying values of accounts receivables, accounts payables (including accrued liabilities), restricted investments and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at March 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 7 for the estimated fair value of our outstanding fixed-rate debt.

14


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The fair market values of the derivative financial instruments reflected on the balance sheets as of March 31, 2016 and December 31, 2015 were based on estimated forward commodity prices and forward interest rate yield curves. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

 

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

 

 

Fair Value Measurements at March 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

$

 

 

$

776,805

 

 

$

 

 

$

776,805

 

Interest rate derivatives

 

 

 

 

28

 

 

 

 

 

 

28

 

Total assets

$

 

 

$

776,833

 

 

$

 

 

$

776,833

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

$

 

 

$

72,788

 

 

$

 

 

$

72,788

 

Interest rate derivatives

 

 

 

 

5,834

 

 

 

 

 

 

5,834

 

Total liabilities

$

 

 

$

78,622

 

 

$

 

 

$

78,622

 

 

 

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 5 for additional information regarding our derivative instruments.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

 

·

The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding factors such as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 6 for a summary of changes in AROs.

 

·

If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital.

 

·

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. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, estimates of 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 natural gas properties.

 

15


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

 

·

During the three months ended March 31 2016, we recognized $8.3 million of impairments related to certain properties located 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.  As a result of the impairments, the carrying value of these properties was reduced to approximately $11.0 million. We recorded approximately $251.3 million of impairments during the three months ended March 31, 2015 primarily related to certain properties located in East Texas, Wyoming and Colorado. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable in part due to a downward revision of estimated proved reserves based on declining commodity prices and increased operating costs. 

 

 

Note 5. Risk Management and Derivative Instruments

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

Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreement are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. As a result, had all counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $332.2 million against amounts outstanding under our revolving credit facility at March 31, 2016, reducing our maximum credit exposure to approximately $369.1 million, of which approximately $213.5 million was with two counterparties. See Note 7 for additional information regarding our revolving credit facility.

Commodity Derivatives

We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, costless collars and basis swaps) to manage exposure to commodity price volatility. Historically, the Partnership has not paid or received premiums for put options. In February 2015, we restructured a portion of our commodity derivative portfolio by effectively terminating “in-the-money” crude oil derivatives settling in 2015 through 2017 and entering into NGL derivatives with the same tenor.  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.

16


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub and regional indices such as NGPL TXOK, TETCO STX, CIG and Houston Ship Channel in proximity to our areas of production. We also enter into oil derivative contracts indexed to a variety of locations such as NYMEX-CL, ICE Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu. At March 31, 2016, we had the following open commodity positions:

 

 

 

Remaining

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2016

 

 

2017

 

 

2018

 

 

2019

 

Natural Gas Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed price swap contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

 

3,586,331

 

 

 

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)

 

 

3,572,778

 

 

 

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)

 

 

304,313

 

 

 

301,600

 

 

 

312,000

 

 

 

160,000

 

Weighted-average fixed price

 

$

85.47

 

 

$

85.00

 

 

$

83.74

 

 

$

85.52

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

 

139,667

 

 

 

67,500

 

 

 

 

 

 

 

Spread

 

$

(10.01

)

 

$

(7.82

)

 

$

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed price swap contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

 

210,433

 

 

 

43,300

 

 

 

 

 

 

 

Weighted-average fixed price

 

$

35.79

 

 

$

37.55

 

 

$

 

 

$

 

 

Our basis swaps included in the table above are presented on a disaggregated basis below:

 

 

 

Remaining

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2016

 

 

2017

 

 

2018

 

 

2019

 

Natural Gas Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NGPL TexOk basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

 

2,997,778

 

 

 

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)

 

 

99,667

 

 

 

37,500

 

 

 

 

 

 

 

Spread - Brent

 

$

(12.29

)

 

$

(12.20

)

 

$

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Midland basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

 

40,000

 

 

 

30,000

 

 

 

 

 

 

 

Spread - WTI

 

$

(4.34

)

 

$

(2.35

)

 

$

 

 

$

 

 

17


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Interest Rate Swaps

Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. From time to time we enter into offsetting positions to avoid being economically over-hedged. At March 31, 2016, we had the following interest rate swap open positions:

 

 

 

Remaining

 

 

 

 

 

 

 

 

 

 

 

2016

 

 

2017

 

 

2018

 

Average Monthly Notional (in thousands)

 

$

400,000

 

 

$

400,000

 

 

$

300,000

 

Weighted-average fixed rate

 

 

0.943

%

 

 

1.612

%

 

 

1.427

%

Floating rate

 

1 Month LIBOR

 

 

1 Month LIBOR

 

 

1 Month LIBOR

 

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 March 31, 2016 and December 31, 2015. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement.

 

 

 

 

 

Asset Derivatives

 

 

Liability Derivatives

 

 

 

 

 

March 31,

 

 

December 31,

 

 

March 31,

 

 

December 31,

 

Type

 

Balance Sheet Location

 

2016

 

 

2015

 

 

2016

 

 

2015

 

 

 

 

 

(In thousands)

 

Commodity contracts

 

Short-term derivative instruments

 

$

308,480

 

 

$

324,265

 

 

$

48,530

 

 

$

53,581

 

Interest rate swaps

 

Short-term derivative instruments

 

 

 

 

 

 

 

 

2,194

 

 

 

1,214

 

Gross fair value

 

 

 

 

308,480

 

 

 

324,265

 

 

 

50,724

 

 

 

54,795

 

Netting arrangements

 

Short-term derivative instruments

 

 

(48,626

)

 

 

(51,945

)

 

 

(48,626

)

 

 

(51,945

)

Net recorded fair value

 

Short-term derivative instruments

 

$

259,854

 

 

$

272,320

 

 

$

2,098

 

 

$

2,850

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Long-term derivative instruments

 

$

468,325

 

 

$

492,730

 

 

$

24,258

 

 

$

30,920

 

Interest rate swaps

 

Long-term derivative instruments

 

 

28

 

 

 

 

 

 

3,640

 

 

 

1,441

 

Gross fair value

 

 

 

 

468,353

 

 

 

492,730

 

 

 

27,898

 

 

 

32,361

 

Netting arrangements

 

Long-term derivative instruments

 

 

(25,737

)

 

 

(30,920

)

 

 

(25,737

)

 

 

(30,920

)

Net recorded fair value

 

Long-term derivative instruments

 

$

442,616

 

 

$

461,810

 

 

$

2,161

 

 

$

1,441

 

(Gains) Losses on Derivatives

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

 

 

 

 

 

For the Three Months Ended

 

 

 

Statements of

 

March 31,

 

 

 

Operations Location

 

2016

 

 

2015

 

Commodity derivative contracts

 

(Gain) loss on commodity derivatives

 

$

(51,745

)

 

$

(145,459

)

Interest rate derivatives

 

Interest expense, net

 

 

3,682

 

 

 

2,441

 

 

 

18


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 6. Asset Retirement Obligations

The Partnership’s asset retirement obligations primarily relate to the Partnership’s portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the three months ended March 31, 2016 (in thousands):

 

Asset retirement obligations at beginning of period

 

$

164,164

 

Liabilities added from acquisitions or drilling

 

 

10

 

Liabilities removed upon sale of wells

 

 

(451

)

Liabilities settled

 

 

(615

)

Accretion expense

 

 

2,707

 

Revision of estimates

 

 

324

 

Asset retirement obligations at end of period

 

 

166,139

 

Less: Current portion

 

 

1,175

 

Asset retirement obligations - long-term portion

 

$

164,964

 

 

 

Note 7. Long Term Debt

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

 

 

March 31,

 

December 31,

 

 

2016

 

2015

 

 

(In thousands)

 

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

$

792,000

 

$

836,000

 

2021 Senior Notes, fixed-rate, due May 2021 (1) (3)

 

700,000

 

 

700,000

 

2022 Senior Notes, fixed-rate, due August 2022 (2) (3)

 

496,990

 

 

496,990

 

Senior notes debt issuance costs, net

 

(17,497

)

 

(18,297

)

Unamortized discounts

 

(13,509

)

 

(14,114

)

Total long-term debt

$

1,957,984

 

$

2,000,579

 

 

 

(1)

The estimated fair value of our 2021 Senior Notes was $203.0 million and $210.0 million at March 31, 2016 and December 31, 2015, respectively.  

 

 

(2)

The estimated fair value of our 2022 Senior Notes was $135.4 million and $149.1 million at March 31, 2016 and December 31, 2015, respectively.

 

 

(3)

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

 

Subsidiary Guarantors

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

OLLC Revolving Credit Facility

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


19


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Borrowing Base

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

 

 

March 31,

 

 

2016

 

 

(In thousands)

 

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

$

1,175,000

 

Subsequent Event

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

 

·

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;

 

·

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

20


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

 

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.

Weighted-Average Interest Rates

The following table presents the weighted-average interest rates paid, excluding commitment fees, on our consolidated variable-rate debt obligations for the periods presented:

 

 

 

For the Three Months Ended

 

 

 

March 31,

 

 

 

2016

 

 

2015

 

OLLC revolving credit facility

 

 

2.43

%

 

 

1.90

%

 

Unamortized Deferred Financing Costs

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

 

 

 

March 31,

 

 

December 31,

 

 

 

2016

 

 

2015

 

 

 

(In thousands)

 

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

 

$

3,289

 

 

$

3,672

 

2021 Senior Notes (2)

 

 

10,665

 

 

 

11,194

 

2022 Senior Notes (2)

 

 

6,832

 

 

 

7,103

 

Total

 

$

20,786

 

 

$

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.

 

 

Letters of Credit

At March 31, 2016, we had $2.1 million of letters of credit outstanding, all related to operations at our Wyoming properties.

 

 

 

 

 

 


21


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 8. Equity & Distributions

Equity Outstanding

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

 

 

 

 

 

 

General

 

 

Common

 

 

Partner

 

Balance, December 31, 2015

 

82,906,400

 

 

 

86,797

 

Restricted common units issued

 

50,000

 

 

 

 

Restricted common units forfeited

 

(9,669

)

 

 

 

Restricted common units repurchased (1)

 

(21,429

)

 

 

 

Balance, March 31, 2016

 

82,925,302

 

 

 

86,797

 

 

 

(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 approximately $0.1 million for the three months ended March 31, 2016. 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 unaudited condensed consolidated balance sheets. See Note 10 for additional information regarding restricted common units that were granted during the three months ended March 31, 2016.

2015 Repurchases of Common Units

During the three months ended March 31, 2015, we repurchased $28.4 million in common units, which represented a repurchase and retirement of 1,909,583 common units under the December 2014 repurchase program. The December 2014 repurchase program expired in December 2015.      

Allocations of Net Income (Loss)

Net income (loss) attributable to the Partnership is 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 are affiliates of our general partner.

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

 

Payable Date

 

Per Unit

 

 

Distribution

 

 

Affiliates

 

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

 

 

 

22


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 9. Earnings per Unit

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

 

 

For the Three Months Ended

 

 

March 31,

 

 

2016

 

 

2015

 

Net income (loss) attributable to Memorial Production Partners LP

$

(38,097

)

 

$

(162,817

)

Less: Previous owners interest in net income (loss)

 

 

 

 

(2,268

)

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

 

(40

)

 

 

(166

)

Less: IDRs attributable to corresponding period

 

 

 

 

56

 

Less: Phantom unit distribution equivalents attributable to corresponding period (see Note 11)

 

(5

)

 

 

 

Net income (loss) available to limited partners

$

(38,052

)

 

$

(160,439

)

 

 

 

 

 

 

 

 

Weighted average limited partner units outstanding:

 

 

 

 

 

 

 

Common units

 

82,935

 

 

 

81,778

 

Subordinated units

 

 

 

 

2,561

 

Total

 

82,935

 

 

 

84,339

 

Basic and diluted EPU

$

(0.46

)

 

$

(1.90

)

 

    

 

(1)

As a result of repurchases under the December 2014 repurchase program, our general partner had an approximate average 0.1046% and 0.1023% interest in us for the three months ended March 31, 2016 and 2015, respectively.

 

 

 

Note 10. Unit-Based Awards

Restricted Common Units

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

 

 

 

 

 

 

Weighted-

 

 

 

 

 

 

Average Grant

 

 

Number of

 

 

Date Fair Value

 

 

Units

 

 

per Unit (1)

 

Restricted common units outstanding at December 31, 2015

 

1,368,538

 

 

$

17.61

 

Granted (2)

 

50,000

 

 

$

2.41

 

Forfeited

 

(9,669

)

 

$

18.50

 

Vested

 

(102,600

)

 

$

15.96

 

Restricted common units outstanding at March 31, 2016

 

1,306,269

 

 

$

17.15

 

 

 

 

(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 the three months ended March 31, 2016 was $0.1 million based on a grant date market price of $2.41 per unit.

 

 

The unrecognized compensation cost associated with restricted common unit awards was $12.9 million at March 31, 2016. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.66 years. Since the restricted common units are participating securities, distributions received by the restricted common unitholders are generally included in distributions to partners as presented on our unaudited condensed statements of consolidated and combined cash flows.

 

LTIP Modification. On 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 a voluntary 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.

 


23


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Phantom Units

The Partnership issued a total of 155,601 phantom units to the non-employee directors in January 2016 which will vest in January 2017. 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 distribution that we pay to a holder of a common unit. Upon vesting, the phantom unit 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.

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

 

 

For the Three Months Ended

 

 

March 31,

 

 

2016

 

 

2015

 

Equity classified awards

 

 

 

 

 

 

 

Restricted common units

$

2,492

 

 

$

2,341

 

Liability classified awards

 

 

 

 

 

 

 

Phantom units

 

76

 

 

 

 

 

$

2,568

 

 

$

2,341

 

 

 

Note 11. Related Party Transactions

Amounts due to Memorial Resource and certain affiliates of NGP at March 31, 2016 and December 31, 2015 are presented within “Accounts payable affiliates” in the accompanying balance sheets.

NGP Affiliated Companies

During the three months ended March 31, 2016 and 2015, we paid less than $0.1 million and $0.2 million, respectively to Multi-Shot, LLC, an NGP affiliated company, for services related to our drilling and completion activities.

Common Control Acquisitions

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

 

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

 

 

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.

24


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Omnibus Agreement

Memorial Resource provides management, administrative and operating services for us and our general partner pursuant to our omnibus agreement. The following table summarizes the amount of general and administrative expenses recognized under the omnibus agreement that are reflected in the accompanying statements of operations for the periods presented (in thousands):

 

For the Three Months Ended

 

March 31,

 

2016

 

 

2015

 

$

7,449

 

 

$

8,553

 

Subsequent Event.  Upon completion of the announced MEMP GP Acquisition, the omnibus agreement will be terminated.  We will subsequently enter into a transition services agreement with Memorial Resource to manage post-closing separation costs and activities.  See Note 13 for additional information.

Beta Management Agreement

Memorial Resource through its wholly-owned subsidiary Beta Operating Company, LLC provided management and administrative oversight related to our offshore Southern California oil and gas properties in exchange for an annual management fee. Memorial Resource had the right to receive approximately $0.4 million from Rise Energy Beta, LLC annually. This agreement was terminated in November 2015 in connection with the 2015 Beta Acquisition.  

Classic Gas Gathering and Water Disposal Agreements

A discussion of these agreements is included in our 2015 Form 10-K. The amended gas gathering agreement was terminated in November 2015 in connection with a third party’s acquisition of Classic Pipeline and Gathering LLC’s (“Classic Pipeline”) Joaquin gathering system. Additionally, Classic Pipeline assigned its salt water system to OLLC in November 2015. For the three months ended March 31, 2015, we incurred gathering and saltwater disposal fees of approximately $0.9 million under these agreements.

Note 12. Commitments and Contingencies

Litigation & Environmental

As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings. We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows.

At March 31, 2016 and December 31, 2015, we had $0.1 million and $0.2 million of environmental reserves recorded on our balance sheets, respectively. 

Supplemental Bond for Decommissioning Liabilities Trust Agreement

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

 

June 30, 2016

 

$

148,000

 

December 31, 2016

 

$

152,000

 

 

In the event the account balance is less than the contractual amount, we must make additional payments. Interest income earned and deposited in the trust account mitigates the likelihood that additional payments will have to be made by us. As of March 31, 2016, the remaining obligation was approximately $6.0 million. In 2015, the BOEM issued a preliminary report that indicated the estimated costs of decommissioning may further increase, and we expect the amount to be finalized during 2016 after negotiations are completed.

 

The gross held-to-maturity investments held in the trust account as of March 31, 2016 for the U.S. Bank money market cash equivalent was $146.0 million.  

 

25


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 13. Subsequent Events

MEMP GP Acquisition

 

On April 27, 2016, the Partnership entered into an agreement to acquire, among other things, all of the equity interests in MEMP GP from Memorial Resource for cash consideration of approximately $0.8 million.  We expect to close this transaction by the end of the second quarter of 2016, subject to customary closing conditions. In connection with the closing of the transaction, our partnership agreement with be amended and restated to, among other things, (i) to convert MEMP GP’s 0.1% general partnership interest into a non-economic general partner interest, (ii) cancel the incentive distribution rights of the Partnership, and (iii) provide the limited partners of the Partnership the ability to elect the members of MEMP GP’s board of directors beginning with an annual meeting in 2017.  MEMP and Memorial Resource will enter into a transition services agreement to manage post-closing separation costs and activities.

Acquisition of NGP owned IDRs

On April 27, 2016, the Partnership entered into an agreement to acquire the 50% ownership of the IDRs of the Partnership owned by NGP.  This acquisition is expected to close immediately prior to the MEMP GP Acquisition.

Amendment to Credit Facility and Borrowing Base Redetermination

Effective April 14, 2016 the borrowing base under our revolving credit facility was reduced to approximately $925 million in connection with the semi-annual borrowing redetermination by the lenders. In addition, we and our lenders reached an agreement on amending certain terms of our revolving credit facility. For additional information, see Note 7.    

 

 

26


 

ITEM 2.

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 unaudited condensed consolidated and combined financial statements and accompanying notes in “Item 1. Financial Statements” contained herein and our 2015 Form 10-K filed with the SEC on February 24, 2016 and any supplements thereto. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements” in the front of this report.

Overview

We are a Delaware limited partnership formed in April 2011 to own, acquire and exploit oil and natural gas properties in North America. The Partnership is owned 99.9% by its limited partners and 0.1% by its general partner, which is a wholly-owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership’s operations and activities.

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our business activities are conducted through OLLC, our wholly-owned subsidiary, and its wholly-owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties and are principally located in Texas, Louisiana, Colorado, Wyoming and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs with well-known geologic characteristics and long-lived, predictable production profiles and modest capital requirements. As of December 31, 2015:

 

·

Our total estimated proved reserves were approximately 1,268 Bcfe, of which approximately 43% were oil and 63% were classified as proved developed reserves;

 

·

We produced from 3,357 gross (1,960 net) producing wells across our properties, with an average working interest of 58% and the Partnership or Memorial Resource is the operator of record of the properties containing 95% of our total estimated proved reserves; and

 

·

Our average net production for the three months ended December 31, 2015 was 257.3 MMcfe/d, implying a reserve-to-production ratio of approximately 14 years.

 

Recent Developments

MEMP GP Acquisition

 

On April 27, 2016, the Partnership entered into an agreement to acquire, among other things, all of the equity interests in MEMP GP from Memorial Resource for cash consideration of approximately $0.8 million.  We expect to close this transaction by the end of the second quarter of 2016, subject to customary closing conditions. In connection with the closing of the transaction, our partnership agreement with be amended and restated to, among other things, (i) to convert MEMP GP’s 0.1% general partnership interest into a non-economic general partner interest, (ii) cancel the incentive distribution rights of the Partnership, and (iii) provide the limited partners of the Partnership the ability to elect the members of MEMP GP’s board of directors beginning with an annual meeting in 2017.  MEMP and Memorial Resource will enter into a transition services agreement to manage post-closing separation costs and activities.

Acquisition of NGP owned IDRs

On April 27, 2016, the Partnership entered into an agreement to acquire the 50% ownership of the IDRs of the Partnership owned by NGP.  This acquisition is expected to close immediately prior to the MEMP GP Acquisition.

27


 

Amendment to Credit Facility and Borrowing Base Redetermination

 

Effective April 14, 2016 the borrowing base under our revolving credit facility was reduced to approximately $925 million in connection with the semi-annual borrowing redetermination by the lenders. In addition, we and our lenders reached an agreement on amending certain terms of our revolving credit facility. For information regarding the tenth amendment to the Credit Agreement, dated as of December 14, 2011 (as previously amended, the “Credit Agreement”), see Note 7 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Part I, Item 1.

Business Environment and Operational Focus

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

Principal Components of Cost Structure

 

·

Lease operating expenses. These are the day to day costs incurred to maintain production of our natural gas, NGLs and oil. Such costs include utilities, direct labor, water injection and disposal, the cost of CO2 injection, materials and supplies, compression, repairs and workover expenses. Cost levels for these expenses can vary based on supply and demand for oilfield services and activities performed during a specific period.

 

·

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.

 

·

Taxes other than income. These consist of severance, 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 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.

 

·

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

 

·

Impairment of proved properties. Proved properties are impaired whenever the carrying value of the properties exceed their estimated undiscounted future cash flows.

 

·

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.

 

·

General and administrative expense. These costs include overhead, including payroll and benefits for employees, costs of maintaining headquarters, costs of managing production and development operations, compensation expense associated with certain long-term incentive-based plans, audit and other professional fees and legal compliance expenses.

We and our general partner are parties to an omnibus agreement with a wholly-owned subsidiary of Memorial Resource pursuant to which, among other things, Memorial Resource performs all operational, management and administrative services on our general partner’s and our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocated to us, including expenses incurred by our general partner and its affiliates on our behalf. Memorial Resource allocates its indirect general and administrative costs based on estimated time spent on each entity, which it believes accurately reflects the costs incurred to provide services to us. Under our partnership agreement and the omnibus agreement, we reimburse Memorial Resource for all direct and indirect costs incurred on our behalf.

 

·

Interest expense. We finance a portion of our working capital requirements 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.

28


 

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 flows 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;

 

·

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;

 

·

Unit-based compensation expenses;

 

·

Exploration costs;

 

·

Acquisition related costs; and

 

·

Other non-routine items that we deem appropriate.

Less:

 

·

Interest income;

 

·

Income tax benefit;

 

·

Gain on 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.

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

 

·

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 available to pay distributions to our unitholders, develop existing reserves or acquire additional oil and natural gas properties.

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

29


 

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 Three Months Ended

 

 

March 31,

 

 

2016

 

 

2015

 

Net income (loss)

$

(38,097

)

 

$

(162,658

)

Interest expense, net

 

32,552

 

 

 

28,818

 

Income tax expense (benefit)

 

96

 

 

 

(2,370

)

DD&A

 

44,429

 

 

 

51,266

 

Impairment of proved oil and gas properties

 

8,342

 

 

 

251,347

 

Accretion of AROs

 

2,707

 

 

 

1,634

 

(Gains) losses on commodity derivative instruments

 

(51,745

)

 

 

(145,459

)

Cash settlements received (paid) on expired commodity derivative instruments

 

80,221

 

 

 

60,124

 

(Gain) loss on sale of properties

 

(96

)

 

 

 

Acquisition related costs

 

86

 

 

 

1,299

 

Unit-based compensation expense

 

2,568

 

 

 

2,341

 

Exploration costs

 

122

 

 

 

90

 

Loss on settlement of AROs

 

121

 

 

 

 

Adjusted EBITDA

$

81,306

 

 

$

86,432

 

 

Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA

 

 

 

For the Three Months Ended

 

 

 

March 31,

 

 

 

2016

 

 

2015

 

Net cash provided by operating activities

 

$

77,006

 

 

$

71,963

 

Changes in working capital

 

 

(24,268

)

 

 

(11,726

)

Interest expense, net

 

 

32,552

 

 

 

28,818

 

Gain (loss) on interest rate swaps

 

 

(3,682

)

 

 

(2,441

)

Cash settlements paid on interest rate derivative instruments

 

 

530

 

 

 

888

 

Amortization of deferred financing fees

 

 

(1,202

)

 

 

(1,860

)

Accretion of senior notes discount

 

 

(605

)

 

 

(599

)

Acquisition related expenses

 

 

86

 

 

 

1,299

 

Income tax expense (benefit) - current portion

 

 

31

 

 

 

 

Exploration costs

 

 

122

 

 

 

90

 

Plugging and abandonment cost

 

 

736

 

 

 

 

Adjusted EBITDA

 

$

81,306

 

 

$

86,432

 

 

Critical Accounting Policies and Estimates

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

When used in the preparation of our consolidated financial statements, such estimates are based on our current knowledge and understanding of the underlying facts and circumstances and may be revised as a result of actions we take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.

 

 

Results of Operations

The results of operations for the three months ended March 31, 2016 and 2015 have been derived from our consolidated and combined financial statements.

30


 

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

 

 

 

For the Three Months Ended

 

 

 

March 31,

 

 

 

2016

 

 

2015

 

Revenues:

 

 

 

 

 

 

 

 

Oil & natural gas sales

 

$

60,623

 

 

$

91,949

 

Pipeline tariff income and other

 

 

243

 

 

 

869

 

Total revenues

 

 

60,866

 

 

 

92,818

 

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

 

Lease operating

 

 

35,696

 

 

 

40,478

 

Gathering, processing and transportation

 

 

9,209

 

 

 

8,666

 

Exploration

 

 

122

 

 

 

90

 

Taxes other than income

 

 

4,008

 

 

 

6,655

 

Depreciation, depletion and amortization

 

 

44,429

 

 

 

51,266

 

Impairment of proved oil and natural gas properties

 

 

8,342

 

 

 

251,347

 

General and administrative

 

 

13,524

 

 

 

14,511

 

Accretion of asset retirement obligations

 

 

2,707

 

 

 

1,634

 

(Gain) loss on commodity derivative instruments

 

 

(51,745

)

 

 

(145,459

)

Gain on sale of properties

 

 

(96

)

 

 

 

Other, net

 

 

119

 

 

 

 

Total costs and expenses

 

 

66,315

 

 

 

229,188

 

Operating income (loss)

 

 

(5,449

)

 

 

(136,370

)

Other income (expense):

 

 

 

 

 

 

 

 

Interest expense, net

 

 

(32,552

)

 

 

(28,818

)

Other income (expense)

 

 

 

 

 

160

 

Total other income (expense)

 

 

(32,552

)

 

 

(28,658

)

Income before income taxes

 

 

(38,001

)

 

 

(165,028

)

Income tax benefit (expense)

 

 

(96

)

 

 

2,370

 

Net income (loss)

 

 

(38,097

)

 

 

(162,658

)

Net income (loss) attributable to noncontrolling interest

 

 

 

 

 

159

 

Net income (loss) attributable to Memorial Production Partners LP

 

$

(38,097

)

 

$

(162,817

)

 

 

 

 

 

 

 

 

 

Oil and natural gas revenue:

 

 

 

 

 

 

 

 

Oil sales

 

$

29,777

 

 

$

44,253

 

NGL sales

 

 

7,255

 

 

 

12,123

 

Natural gas sales

 

 

23,591

 

 

 

35,573

 

Total oil and natural gas revenue

 

$

60,623

 

 

$

91,949

 

 

 

 

 

 

 

 

 

 

Production volumes:

 

 

 

 

 

 

 

 

Oil (MBbls)

 

 

1,068

 

 

 

1,021

 

NGLs (MBbls)

 

 

663

 

 

 

699

 

Natural gas (MMcf)

 

 

11,753

 

 

 

12,381

 

Total (MMcfe)

 

 

22,138

 

 

 

22,698

 

Average net production (MMcfe/d)

 

 

243.3

 

 

 

252.2

 

 

 

 

 

 

 

 

 

 

Average sales price:

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

$

27.89

 

 

$

43.34

 

NGL (per Bbl)

 

 

10.94

 

 

 

17.34

 

Natural gas (per Mcf)

 

 

2.01

 

 

 

2.87

 

Total (Mcfe)

 

$

2.74

 

 

$

4.05

 

 

 

 

 

 

 

 

 

 

Average unit costs per Mcfe:

 

 

 

 

 

 

 

 

Lease operating expense

 

$

1.61

 

 

$

1.78

 

Gathering, processing and transportation

 

$

0.42

 

 

$

0.38

 

Taxes other than income

 

$

0.18

 

 

$

0.29

 

General and administrative expenses

 

$

0.61

 

 

$

0.64

 

Depletion, depreciation and amortization

 

$

2.01

 

 

$

2.26

 

 

31


 

Three Months Ended March 31, 2016 Compared to the Three Months Ended March 31, 2015

A net loss of $38.1 million was recorded during the three months ended March 31, 2016 compared to a net loss of $162.7 million recorded during the three months ended March 31, 2015.

 

·

Oil, natural gas and NGL revenues for 2016 totaled $60.6 million, a decrease of $31.3 million compared with 2015. Production decreased 0.6 Bcfe (approximately 2%) primarily from decreased drilling activities, flooding in East Texas and a temporary production curtailment at our Bairoil properties. The average realized sales price decreased $1.31 per Mcfe primarily due to lower period-to-period commodity prices. Crude oil volumes comprised approximately 29% of total volumes for 2016 compared to approximately 27% of total volumes for 2015.  The unfavorable volume and pricing variance contributed to an approximate $2.3 million and $29.0 million decrease in revenues, respectively.

 

·

Lease operating expenses were $35.7 million and $40.5 million during 2016 and 2015, respectively. On a per Mcfe basis, lease operating expenses were $1.61 for 2016 compared to $1.78 for 2015.  Reductions in lease operating expenses were a result of our continued focus on improving margins and operational efficiencies.

 

·

Gathering, processing and transportation expenses were $9.2 million and $8.7 million during 2016 and 2015, respectively.  On a per Mcfe basis, gathering, processing and transportation expenses were $0.42 for 2016 compared to $0.38 for 2015.

 

·

Taxes other than income during 2016 totaled $4.0 million, a decrease of $2.6 million compared with 2015 primarily due to lower realized commodity prices. On a per Mcfe basis, taxes other than income decreased to $0.18 for 2016 compared to $0.29 for 2015 as a result of lower realized commodity prices.

 

·

DD&A expense during 2016 was $44.4 million compared to $51.3 million during 2015, a $6.9 million decrease. Decreased production volumes caused DD&A expense to decrease by approximately $1.3 million and the change in the DD&A rate between periods caused DD&A expense to decrease by approximately $5.6 million. The $0.25 decrease in DD&A rate is primarily due to impairments recognized on certain properties over the course of 2015.

 

·

We recognized $8.3 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 primarily due to a downward revision of estimated proved reserves as a result of significant declines in commodity prices.  We recognized $251.3 million of impairments during 2015 primarily related to certain properties in East Texas, Wyoming and Colorado.  The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable in part due to a downward revision of estimated proved reserves based on pricing terms specific to these properties and increased costs.

 

·

General and administrative expenses during 2016 were $13.5 million and included $2.5 million of unit-based compensation expense and approximately $0.1 million of acquisition-related costs.  General and administrative expenses during 2015 totaled $14.5 million and included approximately $2.3 million of unit-based compensation expense and approximately $1.3 million of acquisition-related costs.  For additional information, see Part I, Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements under Item 1.

 

·

Net gains on commodity derivative instruments of $51.7 million were recognized during 2016, consisting of $80.2 million of cash settlement receipts and a $28.5 million decrease in the fair value of open positions. Net gains on commodity derivative instruments of $145.5 million were recognized during 2015, consisting of $60.1 million of cash settlement receipts and an $85.4 million increase in the fair value of open positions.

Given the volatility of commodity prices, it is not possible to predict future reported mark-to-market net gains or losses and the actual net gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If commodity prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower oil, natural gas and NGL prices. However, if commodity prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher oil, natural gas and NGL prices and will, in this context, be viewed as having resulted in an opportunity cost.

 

·

Net interest expense is comprised of interest on our revolving credit facility, interest on our senior notes, amortization of debt issue costs, accretion of net discount associated with our senior notes and gains and losses on interest rate swaps. Interest expense, net totaled $32.6 million during 2016, including losses on interest rate swaps of approximately $3.7 million, amortization of deferred financing fees of approximately $1.2 million, and accretion of net discount associated with our senior notes of $0.6 million. Interest expense, net totaled $28.8 million during 2015, including losses on interest rate swaps of approximately $2.4 million, amortization of deferred financing fees of approximately $1.9 million and accretion of net discounts associated with our senior notes of $0.6 million. The $3.8 million increase in interest expense is primarily due to losses on interest rate swaps and an increase in outstanding borrowings under our revolving credit facility during 2016 compared to 2015.

 

32


 

Average outstanding borrowings under our revolving credit facility were $814.7 million during 2016 compared to $508.1 million during 2015. We had an average of $1.2 billion aggregate principal amount of our senior notes issued and outstanding during both 2016 and 2015.

 

Liquidity and Capital Resources

Overview. Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements will depend on our ability to generate cash in the future. Our primary sources of liquidity and capital resources have historically been cash flows generated by operating activities, borrowings under our revolving credit facility and equity and debt capital markets. In 2016, we expect our funding sources to be cash flows generated from operating activities, available borrowing capacity under our revolving credit facility, access to debt and equity capital markets, and/or divestitures of non-core assets. In 2016, we expect to divest non-core assets in the Permian and Rockies regions. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements.

If cash flows from operations does not meet our expectations, we may reduce our expected level of capital expenditures, reduce distributions to unitholders, and/or fund a portion of our capital expenditures using borrowings under our revolving credit facility, issuances of debt and equity securities or from other sources, such as asset divestitures. Needed capital may not be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by many factors, including the covenants in our revolving credit facility or our indentures. If we are unable to obtain funds when needed or on acceptable terms, we may be unable to finance the capital expenditures necessary to maintain our production or proved reserves.

Revolving Credit Facility. As of March 31, 2016, we had approximately $380.9 million of available borrowing capacity under our revolving credit facility, which is net of $2.1 million in letters of credit. We had $0.8 million of cash and cash equivalents as of March 31, 2016. On April 14, 2016, our borrowing base decreased from $1.175 billion to approximately $925.0 million in connection with its semi-annual redetermination and reduced our available borrowing capacity by $250.0 million. For additional information regarding our revolving credit facility amendments, see Note 7 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Part I, Item 1.

Capital Markets.  We may also have the ability to issue additional equity and debt as needed through public or private offerings of such securities. We have filed a universal shelf registration statement with the SEC to register the offer and sale of our equity or debt securities to assist us in meeting our future working capital needs, capital expenditures, debt service and distributions to our partners.  However, since we no longer qualify as a well-known seasoned issuer, we will need to file a post-effective amendment to the registration statement to convert it to a non-automatic shelf registration statement that we are eligible to use. Such post-effective amendment is subject to review by the SEC and must be declared effective by the SEC, which could delay our ability to raise debt or equity capital under the registration statement and adversely affect our ability to access financing and the capital markets in a timely fashion. We have also filed a shelf registration statement with the SEC which will allow us to issue our common units potentially through an “at the market” equity program in the future at prices and terms to be determined by market conditions and other factors.

Hedging. Commodity hedging has been and remains an important part of our strategy to reduce cash flow volatility. Our hedging activities are intended to support oil, NGL, and natural gas prices at targeted levels and to manage our exposure to commodity price fluctuations. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved reserves over a three-to-six year period at any given point of time. We may, however, from time to time hedge more or less than this approximate range. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. The current market conditions may also impact our ability to enter into future commodity derivative contracts. 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 March 31, 2016, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk.”

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

33


 

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, general partner and (if applicable) holders of our IDRs. 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.  In addition, new covenants included in the tenth amendment to our Credit Agreement may restrict our distributions prospectively.  We intend to make a $2.5 million distribution with respect to the first quarter on May 13, 2016.  See Note 7 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Part I, Item 1 for additional information.

Capital Expenditures.  For the three months ended March 31, 2016, our total capital expenditures, were approximately $24.5 million, which were primarily related to drilling, recompletions and capital workovers.

Government Trust Account. In 2015, the BSEE issued a preliminary report that indicated the estimated cost of decommissioning the offshore production facilities associated with the Beta properties may increase. We are working with BOEM to replace a portion of the funds maintained in the trust account pursuant to the government obligation with one or more surety bonds, which we believe would free up additional cash currently held in the trust account.  At March 31, 2016, there was approximately $146.0 million in the trust account.

Working Capital.  We expect to fund our working capital needs primarily with operating cash flows. We also plan to reinvest a sufficient amount of our operating cash flow to fund our maintenance capital expenditures. Our growth capital expenditures, which include any acquisitions of oil and natural gas properties and related assets, are expected to be primarily funded with external financing sources, including borrowings under our revolving credit facility and/or proceeds from the issuance of additional equity and debt securities. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements. We expect to fund cash distributions to partners primarily with operating cash flows or borrowings under our credit facility. It is our belief that we will continue to have adequate liquidity and capital resources to fund our primary cash requirements.

As of March 31, 2016, we had a working capital balance of $209.6 million primarily due to a net asset balance of $257.8 million of current derivative instruments partially offset by the timing of accruals, which included accrued capital expenditures of approximately $10.0 million, accrued lease operating expense of approximately $16.9 million and accrued interest payable of approximately $28.0 million.

Revolving Credit Facility

OLLC is a party to a $2.0 billion revolving credit facility that matures in March 2018 and is guaranteed by us and all of our current and future subsidiaries (other than certain immaterial subsidiaries). As of March 31, 2016, we had $792.0 million of outstanding borrowings and $2.1 million of outstanding letters of credit.  The borrowing base is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil, natural gas and NGL reserves, which will take into account the prevailing oil, natural gas and NGL prices at such time, as adjusted for the impact of commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. As of March 31, 2016, we believe we were in compliance with all of the financial and other covenants under our revolving credit facility.

For additional information regarding our revolving credit facility amendments and redetermined borrowing base, see Note 7 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Part I, Item 1 for additional information.

2022 Senior Notes

As of March 31, 2016, there was approximately $497.0 million aggregate principal amount of 6.875% senior notes due 2022 (“2022 Senior Notes”) outstanding. The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of 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 supplement thereto.

34


 

2021 Senior Notes

As of March 31, 2016, there was $700.0 million aggregate principal of amount of 7.625% senior notes due 2021 (“2021 Senior Notes”) outstanding. The 2021 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of 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.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the three months ended March 31, 2016 and 2015 has been derived from both our consolidated financial statements and the previous owners’ combined financial statements. The combined financial statements of the previous owner reflect the common control acquisition from Memorial Resource in February 2015. For information regarding the individual components of our cash flow amounts, see the Unaudited Condensed Statements of Consolidated and Combined Cash Flows included under Item 1 of this quarterly report.

 

 

 

For the Three Months Ended

 

 

 

March 31,

 

 

 

2016

 

 

2015

 

Net cash provided by operating activities

 

$

77,006

 

 

$

71,963

 

Net cash used in investing activities

 

 

24,443

 

 

 

79,106

 

Net cash (used in) provided by financing activities

 

 

(52,326

)

 

 

7,246

 

 

Three Months Ended March 31, 2016 Compared to the Three Months Ended March 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 $5.0 million. Production decreased 0.6 Bcfe (approximately 2%) and average realized sales price decreased $1.31 per Mcfe.  During 2016, lease operating expenses were $35.7 million, a decrease of $4.8 million compared to 2015.  Taxes other than income decreased to $4.0 million in 2016 from $6.7 million during 2015. We had a $12.5 million increase due to the timing of working capital.  Net cash provided by operating activities included a $20.5 million period-to-period increase in cash settlements received on expired commodity derivative instruments. The period-to-period increase in cash settlements received on expired commodity derivatives partially offset decreased revenues as previously discussed under “—Results of Operations.”

Investing Activities. Net cash used in investing activities during 2016 was $24.4 million, of which $22.5 million was used for additions to oil and natural gas properties. In addition we received $0.3 million in proceeds from the sale of oil and natural gas properties.  Net cash used in investing activities during 2015 was $79.1 million, of which $3.3 million was used to acquire oil and natural gas properties from third parties and $74.4 million was used for additions to oil and natural gas properties. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our offshore Southern California oil and natural gas properties. Additions to restricted investments were $2.1 million during 2016 compared to $1.4 million during 2015.

Financing Activities. Distributions to partners during 2016 were $8.3 million compared to $46.3 million during 2015. The decrease is due to a decrease in the declared distribution rate. During 2015, we paid $78.0 million to Memorial Resource in connection with a common control acquisition transaction.

The Partnership had net repayments of $44.0 million under its revolving credit facility during 2016. The Partnership had net borrowings of $161.0 million under its revolving credit facility during 2015 that were primarily used to fund a common control acquisition transaction and to fund its drilling program. For additional information regarding the common control acquisition, see Note 11 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Part I, Item 1.

We repurchased $28.4 million in common units during 2015, which represented a repurchase and retirement of 1,909,583 common units under the December 2014 repurchase program. This repurchase program expired in December 2015. 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. See Note 8 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Part I, Item 1 for additional information regarding our 2015 repurchases.

35


 

Contractual Obligations

During the three months ended March 31, 2016, there were no significant changes since those reported in our 2015 Form 10-K filed with the SEC on February 24, 2016.

Off–Balance Sheet Arrangements

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

Recently Issued Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see Note 2 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Part I, Item 1.

 

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. We may enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes. We do not designate these or plan to designate future derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings. We believe that our exposures to market risk have not changed materially since those reported under Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” included in our 2015 Form 10-K.

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our oil, natural gas, and NGL production. To reduce the impact of fluctuations in commodity prices on our revenues, or to protect the economics of property acquisitions, we periodically enter into derivative contracts with respect to a portion of our projected production through various transactions that fix the future prices received. It has been our practice to generally enter into costless collars and fixed price swaps only with lenders under our credit agreement.

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 March 31, 2016, see Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Part I, Item 1.

Interest Rate Risk

Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. See Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Part I, Item 1 of this quarterly report for interest rate swap arrangements that were outstanding at March 31, 2016.

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

 

 

 

March 31, 2016

 

 

 

Carrying

 

 

Estimated

 

Description

 

Amount

 

 

Fair Value

 

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

 

$

681,758

 

 

$

203,000

 

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

 

 

484,226

 

 

 

135,430

 

 

36


 

Counterparty and Customer Credit Risk

We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. In addition, our derivative contracts may expose us to credit risk in the event of nonperformance by counterparties. Some of the lenders, or certain of their affiliates, under our credit agreement are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. These agreements allow us to offset our asset position with our liability position in the event of default by the counterparty. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. At March 31, 2016, after taking into effect netting arrangements, we had counterparty exposure of $369.1 million related to our derivative instruments. As a result, had all counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $332.2 million against amounts outstanding under our revolving credit facility at March 31, 2016.

ITEM 4.

CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

As required by Rules 13a-15(b) and 15d-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer of our general partner, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) and under the Exchange Act) as of the end of the period covered by this quarterly report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including the principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, the principal executive officer and principal financial officer of our general partner have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2016.

Change in Internal Controls Over Financial Reporting

No changes in our internal control over financial reporting occurred during the quarter ended March 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 quarterly report.

 

 

 

37


 

PART II—OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS.

For information regarding legal proceedings, see Part I, Item 1, Financial Statements, Note 12, “Commitments and Contingencies – Litigation & Environmental,” of the Notes to Unaudited Condensed Consolidated Financial Statements included in this quarterly report, which is incorporated herein by reference.

ITEM 1A.

RISK FACTORS.

There have been no material changes with respect to the risk factors since those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015 filed with the SEC on February 24, 2016.    

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

Our general partner’s approximate 0.1% interest in us was represented by 86,797 general partner units at March 31, 2016. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its current general partner interest.

The following table summarizes our repurchase activity during the quarterly period ended March 31, 2016:

 

 

 

 

 

 

 

 

 

 

 

 

 

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)

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2016 - January 31, 2016

 

 

11,801

 

 

$

2.41

 

 

n/a

 

n/a

February 1, 2016 - February 29, 2016

 

 

 

 

$

 

 

n/a

 

n/a

March 1, 2016 - March 31, 2016

 

 

9,628

 

 

$

2.31

 

 

n/a

 

n/a

 

 

(1)

Restricted common units are generally net-settled by unitholders to cover the required withholding tax upon vesting.  See Note 10 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Part I, Item 1 of this quarterly report.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4.

MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5.

OTHER INFORMATION.

Change of Control Agreements

On May 4, 2016, our general partner entered into change of control agreements with each of its executive officers. 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;

38


 

 

·

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.

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.

The foregoing description is not complete and is qualified in its entirety by reference to the full text of the form of change of control agreement, which is attached as Exhibit 10.2 to this Quarterly Report on Form 10-Q and incorporated in this Item 5 by reference.

ITEM 6.

EXHIBITS.

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

 

 

 

39


 

SIGNATURES

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

 

 

Memorial Production Partners LP

 

(Registrant)

 

 

 

 

 

By:

 

Memorial Production Partners GP LLC, its general partner

 

 

 

 

Date: May 4, 2016

By:

 

/s/ Robert L. Stillwell, Jr.

 

Name:

 

Robert L. Stillwell, Jr.

 

Title:

 

Vice President and  Chief  Financial Officer of

 

 

 

Memorial Production Partners GP LLC

 

 

40


 

EXHIBIT INDEX

 

Exhibit
Number

 

 

 

Description

 

 

 

   2.1##

 

 

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).

 

 

 

 

 

   2.2##

 

 

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).

 

 

 

 

 

   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

 

 

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).

 

 

 

 

 

   3.4

 

 

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).

 

 

 

 

 

   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 2, 2016).

 

 

 

 

 

   10.1

 

 

Tenth Amendment to Credit Agreement, dated as of April 14, 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 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on April 14, 2016).

 

 

 

 

 

 

 

   10.2#*

 

 

Form of Change of Control Agreement

 

 

 

 

 

   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.

 

 

 

 

 

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 as an exhibit to this Quarterly Report on Form 10-Q.

**

Furnished as an exhibit to this Quarterly Report on Form 10-Q.

#

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.

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