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EX-32.1 - EX-32.1 - Amplify Energy Corpmemp-ex321_6.htm
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EX-31.1 - EX-31.1 - Amplify Energy Corpmemp-ex311_10.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 June 30, 2015

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 July 31, 2015, the registrant had 82,943,504 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

 

7

 

 

Unaudited Condensed Consolidated and Combined Balance Sheets as of June 30, 2015 and December 31, 2014

 

7

 

 

Unaudited Condensed Statements of Consolidated and Combined Operations for the Three and Six Months Ended June 30, 2015 and 2014

 

8

 

 

Unaudited Condensed Statements of Consolidated and Combined Cash Flows for the Six Months Ended June 30, 2015 and 2014

 

9

 

 

Unaudited Condensed Statements of Consolidated Equity for the Six Months Ended June 30, 2015

 

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

 

13

 

 

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 – Restricted Investments

 

19

 

 

Note 8 – Long Term Debt

 

20

 

 

Note 9 – Equity & Distributions

 

22

 

 

Note 10 – Earnings per Unit

 

23

 

 

Note 11 – Equity-based Awards

 

23

 

 

Note 12 – Related Party Transactions

 

24

 

 

Note 13 – Commitments and Contingencies

 

25

 

 

 

 

 

Item 2.

 

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

 

27

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk

 

37

Item 4.

 

Controls and Procedures

 

38

 

 

PART II—OTHER INFORMATION

 

 

Item 1.

 

Legal Proceedings

 

39

Item 1A.

 

Risk Factors

 

39

Item 2.

 

Unregistered Sales of Equity Securities and Use of Proceeds

 

39

Item 3.

 

Defaults Upon Senior Securities

 

39

Item 4.

 

Mine Safety Disclosures

 

39

Item 5.

 

Other Information

 

39

Item 6.

 

Exhibits

 

40

 

 

 

Signatures

 

41

 

 

 

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.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

1


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.

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).

2


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;

·

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

·

“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 NGL;

·

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.

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 minimum quarterly distribution or any other amount on our common units;

·

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 and in estimating reserves;

·

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

·

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

5


·

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, and volatility in the prices for, oil and natural gas;

·

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, 2014 (“2014 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 AND COMBINED BALANCE SHEETS

(In thousands, except outstanding units)

 

 

June 30,

 

 

December 31,

 

 

2015

 

 

2014*

 

ASSETS

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

$

163

 

 

$

970

 

Accounts receivable:

 

 

 

 

 

 

 

Oil and natural gas sales

 

33,822

 

 

 

46,413

 

Joint interest owners and other (Note 2)

 

28,489

 

 

 

36,937

 

Affiliates

 

1,049

 

 

 

 

Short-term derivative instruments

 

172,644

 

 

 

208,585

 

Prepaid expenses and other current assets

 

14,890

 

 

 

14,201

 

Total current assets

 

251,057

 

 

 

307,106

 

Property and equipment, at cost:

 

 

 

 

 

 

 

Oil and natural gas properties, successful efforts method

 

3,472,853

 

 

 

3,329,338

 

Support equipment and facilities

 

203,074

 

 

 

198,088

 

Other

 

3,193

 

 

 

3,020

 

Accumulated depreciation, depletion and impairment

 

(1,413,864

)

 

 

(1,060,114

)

Property and equipment, net

 

2,265,256

 

 

 

2,470,332

 

Long-term derivative instruments

 

316,758

 

 

 

311,802

 

Restricted investments

 

80,096

 

 

 

77,361

 

Other long-term assets

 

21,266

 

 

 

23,159

 

Total assets

$

2,934,433

 

 

$

3,189,760

 

 

 

 

 

 

 

 

 

LIABILITIES AND EQUITY

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

Accounts payable

$

9,229

 

 

$

23,609

 

Accounts payable - affiliates

 

618

 

 

 

6,409

 

Revenues payable

 

31,718

 

 

 

30,110

 

Accrued liabilities (Note 2)

 

103,030

 

 

 

90,974

 

Short-term derivative instruments

 

2,980

 

 

 

3,289

 

Total current liabilities

 

147,575

 

 

 

154,391

 

Long-term debt (Note 8)

 

1,823,650

 

 

 

1,595,413

 

Asset retirement obligations

 

118,965

 

 

 

112,702

 

Long-term derivative instruments

 

669

 

 

 

 

Deferred tax liabilities

 

2,359

 

 

 

30,940

 

Total liabilities

 

2,093,218

 

 

 

1,893,446

 

Commitments and contingencies (Note 13)

 

 

 

 

 

 

 

Equity:

 

 

 

 

 

 

 

Partners' equity (deficit):

 

 

 

 

 

 

 

Common units (83,520,557 units outstanding at June 30, 2015 and 80,421,992 units outstanding at December 31, 2014)

 

834,386

 

 

 

1,085,265

 

Subordinated units (no outstanding units at June 30, 2015 and 5,360,912 units outstanding at December 31, 2014)

 

 

 

 

(16,419

)

General partner (86,797 units outstanding at June 30, 2015 and December 31, 2014)

 

1,045

 

 

 

1,251

 

Previous owners

 

 

 

 

220,657

 

Total partners' equity

 

835,431

 

 

 

1,290,754

 

Noncontrolling interests

 

5,784

 

 

 

5,560

 

Total equity

 

841,215

 

 

 

1,296,314

 

Total liabilities and equity

$

2,934,433

 

 

$

3,189,760

 

 

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

*See Note 1 for information regarding recast amounts and basis of financial statement presentation.

 

 

 

7


MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS

(In thousands, except per unit amounts)

  

 

 

For the Three Months Ended

 

 

For the Six Months Ended

 

 

 

 

June 30,

 

 

June 30,

 

 

 

 

2015

 

 

2014*

 

 

2015

 

 

2014*

 

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil & natural gas sales

 

$

97,221

 

 

$

142,870

 

 

$

189,170

 

 

$

258,847

 

 

Pipeline tariff income and other

 

 

917

 

 

 

1,338

 

 

 

1,786

 

 

 

2,246

 

 

Total revenues

 

 

98,138

 

 

 

144,208

 

 

 

190,956

 

 

 

261,093

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

 

44,888

 

 

 

27,528

 

 

 

85,366

 

 

 

57,648

 

 

Pipeline operating

 

 

500

 

 

 

676

 

 

 

946

 

 

 

1,165

 

 

Gathering, processing, and transportation

 

 

9,048

 

 

 

7,591

 

 

 

17,268

 

 

 

13,154

 

 

Exploration

 

 

32

 

 

 

204

 

 

 

122

 

 

 

210

 

 

Production and ad valorem taxes

 

 

6,058

 

 

 

7,418

 

 

 

12,713

 

 

 

13,429

 

 

Depreciation, depletion, and amortization

 

 

46,286

 

 

 

42,966

 

 

 

97,552

 

 

 

75,516

 

 

Impairment of proved oil and natural gas properties

 

 

 

 

 

 

 

 

251,347

 

 

 

 

 

General and administrative

 

 

14,377

 

 

 

11,372

 

 

 

28,888

 

 

 

22,112

 

 

Accretion of asset retirement obligations

 

 

1,686

 

 

 

1,400

 

 

 

3,320

 

 

 

2,791

 

 

(Gain) loss on commodity derivative instruments

 

 

61,403

 

 

 

138,346

 

 

 

(84,056

)

 

 

185,112

 

 

Other, net

 

 

(943

)

 

 

 

 

 

(943

)

 

 

(12

)

 

Total costs and expenses

 

 

183,335

 

 

 

237,501

 

 

 

412,523

 

 

 

371,125

 

 

Operating income (loss)

 

 

(85,197

)

 

 

(93,293

)

 

 

(221,567

)

 

 

(110,032

)

 

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net

 

 

(27,910

)

 

 

(18,037

)

 

 

(56,728

)

 

 

(34,115

)

 

Other income (expense)

 

 

124

 

 

 

 

 

 

284

 

 

 

 

 

Total other income (expense)

 

 

(27,786

)

 

 

(18,037

)

 

 

(56,444

)

 

 

(34,115

)

 

Income (loss) before income taxes

 

 

(112,983

)

 

 

(111,330

)

 

 

(278,011

)

 

 

(144,147

)

 

Income tax benefit (expense)

 

 

(876

)

 

 

(310

)

 

 

1,494

 

 

 

(385

)

 

Net income (loss)

 

 

(113,859

)

 

 

(111,640

)

 

 

(276,517

)

 

 

(144,532

)

 

Net income (loss) attributable to noncontrolling interest

 

 

65

 

 

 

(12

)

 

 

224

 

 

 

43

 

 

Net income (loss) attributable to Memorial Production Partners LP

 

$

(113,924

)

 

$

(111,628

)

 

$

(276,741

)

 

$

(144,575

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Limited partners' interest in net income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to Memorial Production Partners LP

 

$

(113,924

)

 

$

(111,628

)

 

$

(276,741

)

 

$

(144,575

)

 

Net (income) loss allocated to previous owners

 

 

 

 

 

(2,566

)

 

 

2,268

 

 

 

(3,731

)

 

Net (income) loss allocated to general partner

 

 

90

 

 

 

94

 

 

 

228

 

 

 

108

 

 

Net (income) loss allocated to NGP IDRs

 

 

(28

)

 

 

(20

)

 

 

(56

)

 

 

(40

)

 

Limited partners' interest in net income (loss)

 

$

(113,862

)

 

$

(114,120

)

 

$

(274,301

)

 

$

(148,238

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings per unit: (Note 10)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic and diluted earnings per unit

 

$

(1.36

)

 

$

(1.86

)

 

$

(3.26

)

 

$

(2.42

)

 

Weighted average limited partner units outstanding:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic and diluted

 

 

83,902

 

 

 

61,464

 

 

 

84,119

 

 

 

61,358

 

 

 

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

*See Note 1 for information regarding recast amounts and basis of financial statement presentation.

 

 

 

8


MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS

(In thousands)

 

 

 

For the Six Months Ended

 

 

 

June 30,

 

 

 

2015

 

 

2014*

 

Cash flows from operating activities:

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(276,517

)

 

$

(144,532

)

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

 

 

 

 

 

 

 

 

Depreciation, depletion, and amortization

 

 

97,552

 

 

 

75,516

 

Impairment of proved oil and natural gas properties

 

 

251,347

 

 

 

 

(Gain) loss on derivative instruments

 

 

(80,970

)

 

 

186,203

 

Cash settlements (paid) received on expired derivative instruments

 

 

112,315

 

 

 

(16,518

)

Cash settlements on terminated commodity derivatives

 

 

27,063

 

 

 

 

Premiums paid for commodity derivatives

 

 

(27,063

)

 

 

 

Deferred income tax expense (benefit)

 

 

(1,637

)

 

 

310

 

Amortization of deferred financing costs

 

 

3,116

 

 

 

1,701

 

Accretion of senior notes net discount

 

 

1,204

 

 

 

739

 

Accretion of asset retirement obligations

 

 

3,320

 

 

 

2,791

 

Amortization of equity awards

 

 

4,906

 

 

 

2,960

 

Settlement of asset retirement obligations

 

 

(780

)

 

 

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

Accounts receivable

 

 

9,668

 

 

 

(19,970

)

Prepaid expenses and other assets

 

 

(849

)

 

 

(73

)

Payables and accrued liabilities

 

 

(11,056

)

 

 

21,239

 

Other

 

 

99

 

 

 

1,949

 

Net cash provided by operating activities

 

 

111,718

 

 

 

112,315

 

Cash flows from investing activities:

 

 

 

 

 

 

 

 

Acquisitions of oil and natural gas properties

 

 

(6,095

)

 

 

(173,000

)

Acquisition post-closing adjustment receipts

 

 

9,570

 

 

 

 

Additions to oil and gas properties

 

 

(128,323

)

 

 

(138,205

)

Additions to other property and equipment

 

 

(83

)

 

 

 

Deposits for property acquisitions

 

 

 

 

 

(70,125

)

Additions to restricted investments

 

 

(2,735

)

 

 

(2,121

)

Net cash used in investing activities

 

 

(127,666

)

 

 

(383,451

)

Cash flows from financing activities:

 

 

 

 

 

 

 

 

Advances on revolving credit facilities

 

 

252,000

 

 

 

418,000

 

Payments on revolving credit facilities

 

 

(22,000

)

 

 

(62,000

)

Deferred financing costs

 

 

(235

)

 

 

(590

)

Repurchase of senior notes

 

 

(2,914

)

 

 

 

Capital contributions from previous owners

 

 

1,912

 

 

 

1,975

 

Proceeds from general partner contributions

 

 

 

 

 

14

 

Distributions to partners

 

 

(92,628

)

 

 

(67,524

)

Distribution to Memorial Resource (see Note 1)

 

 

(78,396

)

 

 

(33,880

)

Restricted units returned to plan

 

 

(7

)

 

 

 

Repurchases under unit repurchase program

 

 

(42,591

)

 

 

 

Net cash provided by financing activities

 

 

15,141

 

 

 

255,995

 

Net change in cash and cash equivalents

 

 

(807

)

 

 

(15,141

)

Cash and cash equivalents, beginning of period

 

 

970

 

 

 

21,698

 

Cash and cash equivalents, end of period

 

$

163

 

 

$

6,557

 

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

*See Note 1 for information regarding recast amounts and basis of financial statement presentation.

 

 

 

9


 

MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

(In thousands)

  

 

Partner's Equity (Deficit)

 

 

 

 

 

 

 

 

 

 

Limited Partners

 

 

General

 

 

Previous

 

 

NGP

 

 

Noncontrolling

 

 

 

 

 

 

Common

 

 

Subordinated

 

 

Partner

 

 

Owners

 

 

IDRs

 

 

Interest

 

 

Total

 

Balance, December 31, 2014*

$

1,085,265

 

 

$

(16,419

)

 

$

1,251

 

 

$

220,657

 

 

$

 

 

$

5,560

 

 

$

1,296,314

 

Net income (loss)

 

(274,331

)

 

 

30

 

 

 

(228

)

 

 

(2,268

)

 

 

56

 

 

 

224

 

 

 

(276,517

)

Contributions

 

 

 

 

 

 

 

 

 

 

1,912

 

 

 

 

 

 

 

 

 

1,912

 

Distributions

 

(89,472

)

 

 

(2,949

)

 

 

(151

)

 

 

 

 

 

(56

)

 

 

 

 

 

(92,628

)

Distribution attributable to net assets transferred (Note 1)

 

(78,318

)

 

 

 

 

 

(78

)

 

 

 

 

 

 

 

 

 

 

 

(78,396

)

Net book value of net assets exchanged (Note 1)

 

250,791

 

 

 

 

 

 

251

 

 

 

(248,321

)

 

 

 

 

 

 

 

 

2,721

 

Amortization of equity awards

 

4,906

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4,906

 

Conversion of subordinated units to common units

 

(19,338

)

 

 

19,338

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common units repurchased under repurchase program (Note 9)

 

(43,930

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(43,930

)

Restricted units repurchased and other

 

(1,187

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1,187

)

Deferred tax liability retained by previous owner (Note 2)

 

 

 

 

 

 

 

 

 

 

28,020

 

 

 

 

 

 

 

 

 

28,020

 

Balance, June 30, 2015

$

834,386

 

 

$

 

 

$

1,045

 

 

$

 

 

$

 

 

$

5,784

 

 

$

841,215

 

 

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

*See Note 1 for information regarding recast amounts and basis of financial statement presentation.

 

 

 

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 there are not different economic environments within the operation of our oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, Colorado, Wyoming, New Mexico and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Partnership’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells.

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

The Partnership is owned 99.9% by its limited partners and 0.1% by MEMP GP, which is a wholly-owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership’s operations and activities. Memorial Resource provides management, administrative and operations personnel to us and our general partner under an omnibus agreement (see Note 12). The Funds, which are three of the private equity funds managed by NGP, collectively control MRD Holdco. The Funds collectively indirectly own 50% of our incentive distribution rights (“IDRs”). The remaining IDRs are owned by our general partner.  

Previous Owners

References to “the previous owners” for accounting and financial reporting purposes refer 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 have been 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. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item.

The ownership interest of the noncontrolling shareholder in the San Pedro Bay Pipeline Company (“SPBPC”), an indirect majority-owned subsidiary of the Partnership, is presented as a noncontrolling interest in the financial statements.

11


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Our results of operations for the three and six months ended June 30, 2015 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”). These unaudited condensed consolidated and combined financial statements and the notes thereto should be read in conjunction with the audited supplemental consolidated and combined financial statements and notes thereto included in our Current Report on Form 8-K filed on April 21, 2015 (our “Recast Form 8-K”), which retrospectively revised certain of our financial and other information to give effect to the Property Swap.

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 Recast Form 8-K.

Accounts Receivable – Joint Interest Owners and Other

Accounts receivable from joint interest owners and other consisted of the following at the dates indicated (in thousands):

 

 

June 30,

 

 

December 31,

 

 

2015

 

 

2014

 

Derivatives expired positions

$

12,627

 

 

$

13,754

 

July 2014 Wyoming Acquisition

 

 

 

 

9,569

 

Joint interest owners

 

10,309

 

 

 

12,714

 

Other

 

5,553

 

 

 

900

 

 

$

28,489

 

 

$

36,937

 

 

Accrued Liabilities

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

 

 

June 30,

 

 

December 31,

 

 

2015

 

 

2014

 

Accrued capital expenditures

$

37,476

 

 

$

36,042

 

Accrued interest payable

 

27,104

 

 

 

24,673

 

Accrued lease operating expense

 

21,397

 

 

 

15,594

 

Accrued ad valorem taxes

 

10,146

 

 

 

8,281

 

Accrued general and administrative expenses

 

1,538

 

 

 

1,276

 

Environmental liability

 

1,147

 

 

 

2,092

 

Other

 

4,222

 

 

 

3,016

 

 

$

103,030

 

 

$

90,974

 

12


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Income Tax

A deferred tax liability was recorded in equity by the previous owners and related to Memorial Resource’s initial public offering and restructuring transactions as it represented a transaction among shareholders.  Subsequent to Memorial Resource’s initial public offering in June 2014, income tax related to the Property Swap was calculated on a separate return basis through February 2015.  The deferred tax liability of approximately $28.0 million associated with the previous owners was retained by them in connection with the closing of the Property Swap transaction and reflected in the equity statement.

Supplemental Cash Flows

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

 

 

 

For the Six Months Ended

 

 

 

June 30,

 

 

 

2015

 

 

2014

 

Supplemental cash flows:

 

 

 

 

 

 

 

 

Cash paid for interest, net of amounts capitalized

 

$

49,369

 

 

$

31,298

 

Noncash investing and financing activities:

 

 

 

 

 

 

 

 

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

 

 

(1,434

)

 

 

(11,286

)

(Increase) decrease in accounts receivable related to acquisitions

 

 

9,570

 

 

 

(4,465

)

Repurchases under unit repurchase program

 

 

2,710

 

 

 

 

Restricted units returned to plan

 

 

1,281

 

 

 

932

 

 

 

New Accounting Pronouncements

Presentation of Debt Issuance Cost.  In April 2015, the Financial Accounting Standards Board ("FASB") issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Partnership does not expect the impact of adopting this guidance to be material to the Partnership’s financial statements and related disclosures.

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

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

 

 

Note 3. Acquisitions and Divestitures

Related Party Acquisitions

See Note 12 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.

2014 Acquisitions

Eagle Ford Acquisition. On March 25, 2014, we closed a transaction to acquire certain oil and natural gas producing properties in the Eagle Ford from a third party (the “Eagle Ford Acquisition”). In addition, we acquired a 30% interest in the seller’s Eagle Ford leasehold.  

13


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Wyoming Acquisition. On July 1, 2014, we consummated a transaction to acquire certain oil and natural gas liquids properties in Wyoming from a third party for an aggregate purchase price of approximately $906.1 million, including customary post-closing adjustments (the “Wyoming Acquisition”).

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

 

 

For the Six Months Ended

 

June 30,

 

 

June 30,

 

2015

 

 

2014

 

 

2015

 

 

2014

 

$

297

 

 

$

1,093

 

 

$

1,596

 

 

$

2,987

 

 

Pro forma Information. In March and July 2014, we closed two third-party acquisitions, as discussed above.  The following unaudited pro forma combined results of operations are provided for the three and six months ended June 30, 2014 as though these third-party acquisitions had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the 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

 

 

For the Six Months Ended

 

 

June 30,

 

 

June 30,

 

 

2014

 

 

2014

 

 

(In thousands, except per unit amounts)

 

Revenues

$

188,009

 

 

$

361,558

 

Net income (loss)

 

(86,319

)

 

 

(106,303

)

Basic and diluted earnings per unit

 

(1.45

)

 

 

(1.80

)

 

 

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) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at June 30, 2015 and December 31, 2014. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 8 for the estimated fair value of our outstanding fixed-rate debt.

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 June 30, 2015 and December 31, 2014 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 June 30, 2015 and December 31, 2014 for each of the fair value hierarchy levels:

 

 

Fair Value Measurements at June 30, 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

$

 

 

$

546,433

 

 

$

 

 

$

546,433

 

Interest rate derivatives

 

 

 

 

 

 

 

 

 

 

 

Total assets

$

 

 

$

546,433

 

 

$

 

 

$

546,433

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

$

 

 

$

57,769

 

 

$

 

 

$

57,769

 

Interest rate derivatives

 

 

 

 

2,911

 

 

 

 

 

 

2,911

 

Total liabilities

$

 

 

$

60,680

 

 

$

 

 

$

60,680

 

 

 

Fair Value Measurements at December 31, 2014 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

$

 

 

$

564,913

 

 

$

 

 

$

564,913

 

Interest rate derivatives

 

 

 

 

1,305

 

 

 

 

 

 

1,305

 

Total assets

 

 

 

$

566,218

 

 

 

 

 

$

566,218

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

$

 

 

$

45,831

 

 

$

 

 

$

45,831

 

Interest rate derivatives

 

 

 

 

3,289

 

 

 

 

 

 

3,289

 

Total liabilities

$

 

 

$

49,120

 

 

$

 

 

$

49,120

 

 

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, 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 six months ended June 30, 2015, we recognized $251.3 million of impairments 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 as a result of declining commodity prices.  The carrying value of these properties after the impairment was approximately $157.6 million.  We did not record any impairments during the three and six months ended June 30, 2014.

 

 

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 $286.1 million against amounts outstanding under our revolving credit facility at June 30, 2015, reducing our maximum credit exposure to approximately $199.7 million, of which approximately $78.1 million was with a single counterparty. See Note 8 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, call spreads 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 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 Inter-Continental Exchange (“ICE”) Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu. At June 30, 2015, we had the following open commodity positions:

 

 

Remaining

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

 

2016

 

 

2017

 

 

2018

 

 

2019

 

Natural Gas Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed price swap contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

3,370,903

 

 

 

3,592,442

 

 

 

3,350,067

 

 

 

3,060,000

 

 

 

2,814,583

 

Weighted-average fixed price

$

4.08

 

 

$

4.14

 

 

$

4.06

 

 

$

4.18

 

 

$

4.31

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Collar contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

350,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted-average floor price

$

4.62

 

 

$

 

 

$

 

 

$

 

 

$

 

Weighted-average ceiling price

$

5.80

 

 

$

 

 

$

 

 

$

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Call spreads (1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

80,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted-average sold strike price

$

5.25

 

 

$

 

 

$

 

 

$

 

 

$

 

Weighted-average bought strike price

$

6.75

 

 

$

 

 

$

 

 

$

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

3,690,000

 

 

 

3,578,333

 

 

 

2,210,000

 

 

 

1,315,000

 

 

 

900,000

 

Spread

$

(0.12

)

 

$

(0.07

)

 

$

(0.04

)

 

$

(0.02

)

 

$

0.01

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed price swap contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

272,531

 

 

 

279,813

 

 

 

301,600

 

 

 

312,000

 

 

 

160,000

 

Weighted-average fixed price

$

91.34

 

 

$

86.87

 

 

$

84.70

 

 

$

83.74

 

 

$

85.52

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Collar contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

5,000

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted-average floor price

$

80.00

 

 

$

 

 

$

 

 

$

 

 

$

 

Weighted-average ceiling price

$

94.00

 

 

$

 

 

$

 

 

$

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

97,000

 

 

 

95,000

 

 

 

30,000

 

 

 

 

 

 

 

Spread

$

(7.06

)

 

$

(9.56

)

 

$

(2.35

)

 

$

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed price swap contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

210,200

 

 

 

213,100

 

 

 

43,300

 

 

 

 

 

 

 

Weighted-average fixed price

$

42.35

 

 

$

35.64

 

 

$

37.55

 

 

$

 

 

$

 

 

(1)

These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps.

 

17


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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

 

 

 

Remaining

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

 

2016

 

 

2017

 

 

2018

 

 

2019

 

Natural Gas Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NGPL TexOk basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

 

3,030,000

 

 

 

3,003,333

 

 

 

1,800,000

 

 

 

1,200,000

 

 

 

900,000

 

Spread-Henry Hub

 

$

(0.11

)

 

$

(0.07

)

 

$

(0.07

)

 

$

(0.03

)

 

$

0.01

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

HSC basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

 

150,000

 

 

 

135,000

 

 

 

115,000

 

 

 

115,000

 

 

 

 

Spread-Henry Hub

 

$

(0.08

)

 

$

0.07

 

 

$

0.14

 

 

$

0.15

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CIG basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

 

210,000

 

 

 

170,000

 

 

 

 

 

 

 

 

 

 

Spread-Henry Hub

 

$

(0.25

)

 

$

(0.30

)

 

$

 

 

$

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TETCO STX basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (MMBtu)

 

 

300,000

 

 

 

270,000

 

 

 

295,000

 

 

 

 

 

 

 

Spread-Henry Hub

 

$

(0.09

)

 

$

0.06

 

 

$

0.03

 

 

$

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Midway-Sunset basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

 

57,000

 

 

 

55,000

 

 

 

 

 

 

 

 

 

 

Spread - Brent

 

$

(9.73

)

 

$

(13.35

)

 

$

 

 

$

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Midland basis swaps:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Monthly Volume (Bbls)

 

 

40,000

 

 

 

40,000

 

 

 

30,000

 

 

 

 

 

 

 

Spread - WTI

 

$

(3.25

)

 

$

(4.34

)

 

$

(2.35

)

 

$

 

 

$

 

 

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 June 30, 2015, we had the following interest rate swap open positions:

 

 

 

Remaining

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

 

2016

 

 

2017

 

 

2018

 

Average Monthly Notional (in thousands)

 

$

391,667

 

 

$

400,000

 

 

$

400,000

 

 

$

100,000

 

Weighted-average fixed rate

 

 

1.123

%

 

 

0.943

%

 

 

1.612

%

 

 

1.946

%

Floating rate

 

1 Month LIBOR

 

 

1 Month LIBOR

 

 

1 Month LIBOR

 

 

1 Month LIBOR

 

18


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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 June 30, 2015 and December 31, 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement.

 

 

 

 

 

Asset Derivatives

 

 

Liability Derivatives

 

 

 

 

 

June 30,

 

 

December 31,

 

 

June 30,

 

 

December 31,

 

Type

 

Balance Sheet Location

 

2015

 

 

2014

 

 

2015

 

 

2014

 

 

 

 

 

(In thousands)

 

Commodity contracts

 

Short-term derivative instruments

 

$

194,811

 

 

$

225,882

 

 

$

22,835

 

 

$

17,297

 

Interest rate swaps

 

Short-term derivative instruments

 

 

 

 

 

 

 

 

2,312

 

 

 

3,289

 

Gross fair value

 

 

 

 

194,811

 

 

 

225,882

 

 

 

25,147

 

 

 

20,586

 

Netting arrangements

 

Short-term derivative instruments

 

 

(22,167

)

 

 

(17,297

)

 

 

(22,167

)

 

 

(17,297

)

Net recorded fair value

 

Short-term derivative instruments

 

$

172,644

 

 

$

208,585

 

 

$

2,980

 

 

$

3,289

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Long-term derivative instruments

 

$

351,622

 

 

$

339,031

 

 

$

34,934

 

 

$

28,534

 

Interest rate swaps

 

Long-term derivative instruments

 

 

 

 

 

1,305

 

 

 

599

 

 

 

 

Gross fair value

 

 

 

 

351,622

 

 

 

340,336

 

 

 

35,533

 

 

 

28,534

 

Netting arrangements

 

Long-term derivative instruments

 

 

(34,864

)

 

 

(28,534

)

 

 

(34,864

)

 

 

(28,534

)

Net recorded fair value

 

Long-term derivative instruments

 

$

316,758

 

 

$

311,802

 

 

$

669

 

 

$

 

 

(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 three and six months ended June 30, 2015 and 2014 (in thousands):  

 

 

 

 

 

For the Three Months Ended

 

 

For the Six Months Ended

 

 

 

Statements of

 

June 30,

 

 

June 30,

 

 

 

Operations Location

 

2015

 

 

2014

 

 

2015

 

 

2014

 

Commodity derivative contracts

 

(Gain) loss on commodity derivatives

 

$

61,403

 

 

$

138,346

 

 

$

(84,056

)

 

$

185,112

 

Interest rate derivatives

 

Interest expense, net

 

 

644

 

 

 

776

 

 

 

3,085

 

 

 

1,091

 

 

 

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 six months ended June 30, 2015 (in thousands):

 

Asset retirement obligations at beginning of period

$

112,702

 

Liabilities added from acquisitions or drilling

 

3,214

 

Liabilities removed upon sale of wells

 

(62

)

Liabilities settled

 

(780

)

Accretion expense

 

3,320

 

Revision of estimates

 

571

 

Asset retirement obligations at end of period

$

118,965

 

 

 

Note 7. Restricted Investments

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our offshore Southern California oil and gas properties.

19


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

The components of the restricted investment balance consisted of the following at the dates indicated:

 

 

June 30,

 

 

December 31,

 

 

2015

 

 

2014

 

 

(In thousands)

 

BOEM platform abandonment (See Note 13)

$

72,452

 

 

$

69,954

 

BOEM lease bonds

 

794

 

 

 

794

 

 

 

 

 

 

 

 

 

SPBPC Collateral:

 

 

 

 

 

 

 

Contractual pipeline and surface facilities abandonment

 

2,938

 

 

 

2,701

 

California State Lands Commission pipeline right-of-way bond

 

3,005

 

 

 

3,005

 

City of Long Beach pipeline facility permit

 

500

 

 

 

500

 

Federal pipeline right-of-way bond

 

307

 

 

 

307

 

Port of Long Beach pipeline license

 

100

 

 

 

100

 

Restricted investments

$

80,096

 

 

$

77,361

 

 

 

Note 8. Long Term Debt

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

 

 

June 30,

 

 

December 31,

 

 

2015

 

 

2014

 

 

(In thousands)

 

MEMP:

 

 

 

 

 

 

 

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

$

642,000

 

 

$

412,000

 

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

 

700,000

 

 

 

700,000

 

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

 

496,990

 

 

 

500,000

 

Unamortized discounts

 

(15,340

)

 

 

(16,587

)

Total long-term debt

$

1,823,650

 

 

$

1,595,413

 

 

(1)

The estimated fair value of our 2021 Senior Notes was $669.4 million and $563.5 million at June 30, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

(2)

The estimated fair value of our 2022 Senior Notes was $454.8 million and $380.0 million at June 30, 2015 and December 31, 2014, respectively.  The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

 

Subsidiary Guarantors

We are a “Well-Known Seasoned Issuer” under SEC rules and have filed a universal shelf registration statement with the SEC that allows us to issue debt and equity securities. Any debt securities issued will be governed by an indenture. Our outstanding debt securities are, and any debt securities issued in the future will likely be, jointly and severally, fully and unconditionally guaranteed (subject to customary release provisions) by certain of the Partnership’s subsidiaries (collectively, the “Guarantor Subsidiaries”). The Guarantor Subsidiaries are 100% owned by the Partnership. The Partnership has no material assets or operations independent of the Guarantor Subsidiaries and there are no significant restrictions upon the ability of the Guarantor Subsidiaries to distribute funds to the Partnership.

Borrowing Base

Credit facilities tied to 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:

 

 

June 30,

 

 

2015

 

 

(In thousands)

 

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

$

1,300,000

 

 

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).

20


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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

 

 

For the Six Months Ended

 

 

June 30,

 

 

June 30,

 

 

2015

 

 

2014

 

 

2015

 

 

2014

 

OLLC revolving credit facility

 

2.08

%

 

 

2.09

%

 

 

2.01

%

 

 

1.98

%

 

Unamortized Deferred Financing Costs

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

 

 

June 30,

 

 

December 31,

 

 

2015

 

 

2014

 

 

(In thousands)

 

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

$

4,972

 

 

$

6,468

 

2021 Senior Notes (2)

 

12,251

 

 

 

13,308

 

2022 Senior Notes (2)

 

7,582

 

 

 

7,958

 

Total

$

24,805

 

 

$

27,734

 

 

(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 June 30, 2015, we had $4.8 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 9. Equity & Distributions

Equity Outstanding

The following table summarizes changes in the number of outstanding units since December 31, 2014:

 

 

 

 

 

 

 

 

 

 

General

 

 

Common

 

 

Subordinated

 

 

Partner

 

Balance, December 31, 2014

 

80,421,992

 

 

 

5,360,912

 

 

 

86,797

 

Restricted common units issued

 

795,077

 

 

 

 

 

 

 

Restricted common units forfeited

 

(19,739

)

 

 

 

 

 

 

Restricted common units repurchased (1)

 

(86,073

)

 

 

 

 

 

 

Common units repurchased under repurchase program

 

(2,951,612

)

 

 

 

 

 

 

Subordinated units converted to common units

 

5,360,912

 

 

 

(5,360,912

)

 

 

 

Balance, June 30, 2015

 

83,520,557

 

 

 

 

 

 

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 $1.3 million for the six months ended June 30, 2015. 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 11 for additional information regarding restricted common units that were granted during the six months ended June 30, 2015.

On February 13, 2015, all of the 5,360,912 outstanding subordinated units owned by MRD Holdco were converted into common units. The subordinated units converted on a one-for-one basis into common units upon the payment of MEMP's fourth quarter 2014 distribution.  MRD Holdco sold all of the common units during the three months ended June 30, 2015 and no longer owns any of our outstanding common units.

2015 Repurchases of Common Units

In December 2014, the board of directors of our general partner authorized the repurchase of up to $150.0 million of our common units (“MEMP Repurchase Program”). Under the MEMP Repurchase Program, units may be repurchased and retired from time to time at our discretion on the open market. The MEMP Repurchase Program does not obligate us to repurchase any dollar amount or specific number of common units and may be discontinued at any time. During the six months ended June 30, 2015, we repurchased $43.9 million in common units, which represents a repurchase and retirement of 2,951,612 common units under the MEMP Repurchase Program.  At June 30, 2015, we have up to approximately $90.6 million of authorized repurchases remaining under the MEMP Repurchase Program.

Subsequent Event. We repurchased an additional $8.9 million of our common units, representing 596,309 common units under the MEMP Repurchase Program from the balance sheet date through July 31, 2015.  At July 31, 2015, we have up to approximately $81.7 million of authorized repurchases remaining under the MEMP Repurchase Program.

Allocations of Net Income (Loss)

Net income (loss) attributable to the Partnership is allocated between our general partner and the common and subordinated unitholders in proportion to their pro rata ownership after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated to our general partner and 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.

22


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Cash Distributions to Unitholders

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Distribution

 

 

 

 

 

 

 

 

 

Amount

 

 

Aggregate

 

 

Received by

 

Quarter

 

Declaration Date

 

Record Date

 

Payable Date

 

Per Unit

 

 

Distribution

 

 

Affiliates

 

2nd Quarter 2015

 

July 24, 2015

 

August 5, 2015

 

August 12, 2015

 

$

0.5500

 

 

$

45.7

 

 

$

0.1

 

1st Quarter 2015

 

April 24, 2015

 

May 6, 2015

 

May 13, 2015

 

$

0.5500

 

 

$

46.3

 

 

$

0.2

 

4th Quarter 2014

 

January 26, 2015

 

February 5, 2015

 

February 12, 2015

 

$

0.5500

 

 

$

46.3

 

 

$

3.1

 

3rd Quarter 2014

 

October 23, 2014

 

November 5, 2014

 

November 12, 2014

 

$

0.5500

 

 

$

47.8

 

 

$

3.1

 

2nd Quarter 2014

 

July 24, 2014

 

August 5, 2014

 

August 12, 2014

 

$

0.5500

 

 

$

39.5

 

 

$

3.0

 

1st Quarter 2014

 

April 24, 2014

 

May 6, 2014

 

May 13, 2014

 

$

0.5500

 

 

$

33.8

 

 

$

3.0

 

4th Quarter 2013

 

January 24, 2014

 

February 6, 2014

 

February 13, 2014

 

$

0.5500

 

 

$

33.8

 

 

$

3.0

 

 

 

Note 10. Earnings per Unit

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

 

 

For the Three Months Ended

 

 

For the Six Months Ended

 

 

June 30,

 

 

June 30,

 

 

2015

 

 

2014

 

 

2015

 

 

2014

 

Net income (loss) attributable to Memorial Production Partners LP

$

(113,924

)

 

$

(111,628

)

 

$

(276,741

)

 

$

(144,575

)

Less: Previous owners interest in net income (loss)

 

 

 

 

2,566

 

 

 

(2,268

)

 

 

3,731

 

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

 

(117

)

 

 

(114

)

 

 

(285

)

 

 

(148

)

Less: IDRs attributable to corresponding period

 

54

 

 

 

40

 

 

 

110

 

 

 

80

 

Net income (loss) available to limited partners

$

(113,861

)

 

$

(114,120

)

 

$

(274,298

)

 

$

(148,238

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average limited partner units outstanding:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common units

 

83,902

 

 

 

56,103

 

 

 

82,845

 

 

 

55,997

 

Subordinated units

 

 

 

 

5,361

 

 

 

1,274

 

 

 

5,361

 

Total

 

83,902

 

 

 

61,464

 

 

 

84,119

 

 

 

61,358

 

Basic and diluted EPU

$

(1.36

)

 

$

(1.86

)

 

$

(3.26

)

 

$

(2.42

)

 

(1)

As a result of repurchases under the MEMP Repurchase Program, our general partner had an average 0.103% interest in us for the three and six months ended June 30, 2015.

 

 

Note 11. Equity-Based Awards

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, 2014

 

1,093,520

 

 

$

20.93

 

Granted (2)

 

795,077

 

 

$

15.04

 

Forfeited

 

(19,739

)

 

$

19.48

 

Vested

 

(476,057

)

 

$

20.36

 

Restricted common units outstanding at June 30, 2015

 

1,392,801

 

 

$

17.78

 

 

 

(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 six months ended June 30, 2015 was $12.0 million based on a grant date market price from $14.94 to $15.45 per unit.

23


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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

 

For the Three Months Ended

 

 

For the Six Months Ended

 

June 30,

 

 

June 30,

 

2015

 

 

2014

 

 

2015

 

 

2014

 

$

2,565

 

 

$

1,665

 

 

$

4,906

 

 

$

2,960

 

 

The unrecognized compensation cost associated with restricted common unit awards was $23.2 million at June 30, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.23 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.

 

 

Note 12. Related Party Transactions

Amounts due to (due from) Memorial Resource and certain affiliates of NGP at June 30, 2015 and December 31, 2014 are presented as “Accounts receivable affiliates” and “Accounts payable affiliates” in the accompanying balance sheets.

Common Control Acquisitions

February 2015 Acquisition. On February 23, 2015, we consummated a common control transaction whereby Memorial Resource exchanged its East Texas and West Louisiana properties for all of our interest in the Terryville Field in North Louisiana and cash consideration of approximately $78.4 million, including estimated customary purchase price adjustments. The transaction had an effective date of January 1, 2015. The properties MEMP received are primarily located in the Joaquin Field in Shelby and Panola counties in East Texas. This acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information has been retrospectively revised to give effect to such acquisition as if the Partnership owned the assets for the period after common control commenced through the acquisition date.   The Partnership recorded the following net assets (in thousands):

 

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

 

 

April 2014 Acquisition.  On April 1, 2014, we acquired certain oil and natural gas properties in East Texas from a subsidiary of MRD LLC, for approximately $33.3 million, including estimated customary post-closing adjustments.  The acquired properties primarily represented additional working interests in wells that were already owned by us and located in Polk and Tyler Counties in the Double A Field of East Texas as well as the Sunflower, Segno and Sugar Creek Fields.  This acquisition was accounted for as a transaction with an entity under common control whereby the acquisition was recorded at historical cost at the acquisition date.  The Partnership recorded the following net assets (in thousands):

 

Property and equipment, net

$

37,838

 

Asset retirement obligations

 

(908

)

Other current liabilities

 

(722

)

Net assets

$

36,208

 

Due to common control considerations, the difference between the purchase price and the total net assets was recorded as an equity contribution.

 

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

 

 

For the Six Months Ended

 

June 30,

 

 

June 30,

 

2015

 

 

2014

 

 

2015

 

 

2014

 

$

8,456

 

 

$

5,411

 

 

$

17,009

 

 

$

10,259

 

 

Beta Management Agreement

Memorial Resource through its wholly-owned subsidiary Beta Operating Company, LLC provides management and administrative oversight related to our offshore Southern California oil and gas properties in exchange for an annual management fee. Memorial Resource will receive approximately $0.4 million from us annually.

Classic Agreements

In November 2011, Classic Hydrocarbons Operating, LLC, a subsidiary of Memorial Resource (“Classic Operating”) and Classic Pipeline & Gathering, LLC (“Classic Pipeline”), a subsidiary of MRD Holdco, entered into a gas gathering agreement.  Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. In May 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement has a term until December 31, 2023, subject to one-year extensions at either party’s election.

In May 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement has a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline. In February 2015, in connection with and as part of the Property Swap, Classic Hydrocarbons Holdings, L.P. sold all of the equity interests owned by it in Classic Operating as well as Craton Energy GP III, LLC (“Craton GP”) and Craton Energy Holdings III, LP (“Craton LP”), two subsidiaries of Memorial Resource, to OLLC, and Classic Operating, Craton GP and Craton LP were merged into OLLC.  OLLC is therefore the successor to Classic Operating under the amended gas gathering agreement and water disposal agreement.  

 

 

Note 13. Commitments and Contingencies

Litigation & Environmental

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

At June 30, 2015 and December 31, 2014, we had $1.1 million and $2.1 million of environmental reserves recorded on our balance sheets, respectively. 

25


MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Supplemental Bond for Decommissioning Liabilities Trust Agreement

In connection with its 2009 acquisition of the Beta properties, Rise Energy Operating, LLC (“REO”), our wholly-owned subsidiary, assumed an obligation with the BOEM for the decommissioning of the offshore production facilities.  The trust account is held by REO for the benefit of all working interest owners. The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of June 30, 2015 (in thousands):

 

 

 

Amortized

 

Investment

 

Cost

 

U.S. Bank Money Market Cash Equivalent

 

$

140,003

 

Less: Outside working interest owners share

 

 

(67,551

)

 

 

$

72,452

 

 

The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands):

 

June 30, 2016

 

$

76,590

 

December 31, 2016

 

$

78,660

 

 

As of June 30, 2015, the maximum remaining obligation net to REO’s interest was approximately $6.2 million.

 

 

 

 

 

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 financial statements and accompanying notes in “Item 1. Financial Statements” contained herein and our Recast Form 8-K. 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 by MRD LLC 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, New Mexico 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, 2014:

·

Our total estimated proved reserves were approximately 1,683 Bcfe, of which approximately 43% were natural gas and 58% were classified as proved developed reserves;

·

We produced from 3,568 gross (2,087 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 94% of our total estimated proved reserves; and

·

Our average net production for the three months ended December 31, 2014 was 251 MMcfe/d, implying a reserve-to-production ratio of approximately 18 years.

Recent Developments

Borrowing Base Redetermination

In March 2015, in connection with the semi-annual borrowing base redetermination by lenders under the Partnership’s revolving credit facility, the borrowing base under the revolving credit facility decreased from $1.44 billion to $1.3 billion. This reduction in the borrowing base was primarily the result of the deterioration of commodity prices in the oil and natural gas industry. The new borrowing base became effective on March 24, 2015.

2015 Acquisition

 

In February 2015, we and Memorial Resource completed a transaction in which we exchanged our oil and gas properties in North Louisiana and approximately $78.4 million in cash for Memorial Resource’s East Texas and West Louisiana oil and gas properties (the “Property Swap”).  Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee, which is comprised entirely of independent directors.  

Conversion of Subordinated Units

 

In February 2015, the subordination period for the 5,360,912 subordinated units ended.  All of the subordinated units, which were owned by MRD Holdco, converted to common units on a one-to-one basis at the end of the subordination period. MRD Holdco sold all of the common units during the three months ended June 30, 2015 and no longer owns any of our outstanding common units.

MEMP Repurchase Program

 

In December 2014, the board of directors of our general partner authorized the repurchase of up to $150.0 million of our common units (“MEMP Repurchase Program”).  In 2015, we repurchased $52.8 million in common units through July 31, 2015, which represents a repurchase and retirement of 3,547,921 common units under the MEMP Repurchase Program.

27


 

Business Environment and Operational Focus

Our primary business objective is to generate stable cash flows, allowing us to make quarterly cash distributions to our unitholders and, over time, to 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.

·

Production and ad valorem taxes. These consist of severance and ad valorem taxes. Production taxes are paid on produced natural gas, NGLs and oil based on a percentage of market prices and at fixed per unit rates established by federal, state or local taxing authorities. We take full advantage of all credits and exemptions in the various taxing jurisdictions where we operate. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties; however, these valuations are reasonably correlated to revenues, excluding the effects of any commodity derivative contracts.

·

Exploration expense. These are geological and geophysical costs and include seismic costs, costs of unsuccessful exploratory dry holes 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, franchise taxes, 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 as we continue to grow.

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, including gains or losses on interest rate derivative contracts;

·

Income tax expense;

28


 

·

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

·

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

·

Accretion of asset retirement obligations (“AROs”);

·

Loss on commodity derivative instruments;

·

Cash settlements received on expired commodity derivative instruments;

·

Losses on sale of assets and other, net;

·

Unit-based compensation expenses;

·

Exploration costs;

·

Acquisition related costs;

·

Amortization of investment premium; and

·

Other non-routine items that we deem appropriate.

Less:

·

Interest income;

·

Income tax benefit;

·

Gain on expired commodity derivative instruments;

·

Cash settlements paid on expired commodity derivative instruments;

·

Gains on sale of assets and other, net; and

·

Other non-routine items that we deem appropriate.

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

 

 

For the Six Months Ended

 

 

June 30,

 

 

June 30,

 

 

2015

 

 

2014

 

 

2015

 

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

$

(113,859

)

 

$

(111,640

)

 

$

(276,517

)

 

$

(144,532

)

Interest expense, net

 

27,910

 

 

 

18,037

 

 

 

56,728

 

 

 

34,115

 

Income tax expense (benefit)

 

876

 

 

 

310

 

 

 

(1,494

)

 

 

385

 

DD&A

 

46,286

 

 

 

42,966

 

 

 

97,552

 

 

 

75,516

 

Impairment of proved oil and gas properties

 

 

 

 

 

 

 

251,347

 

 

 

 

Accretion of AROs

 

1,686

 

 

 

1,400

 

 

 

3,320

 

 

 

2,791

 

(Gains) losses on commodity derivative instruments

 

61,403

 

 

 

138,346

 

 

 

(84,056

)

 

 

185,112

 

Cash settlements received (paid) on expired commodity derivative instruments

 

54,351

 

 

 

(7,906

)

 

 

114,475

 

 

 

(15,875

)

Acquisition related costs

 

297

 

 

 

1,093

 

 

 

1,596

 

 

 

2,987

 

Unit-based compensation expense

 

2,565

 

 

 

1,665

 

 

 

4,906

 

 

 

2,960

 

Exploration costs

 

32

 

 

 

204

 

 

 

122

 

 

 

210

 

Loss on settlement of AROs

 

1,328

 

 

 

 

 

 

1,328

 

 

 

 

Provision for environmental remediation

 

 

 

 

 

 

 

 

 

 

2,852

 

Adjusted EBITDA

$

82,875

 

 

$

84,475

 

 

$

169,307

 

 

$

146,521

 

Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA

 

 

For the Three Months Ended

 

 

For the Six Months Ended

 

 

June 30,

 

 

June 30,

 

 

2015

 

 

2014

 

 

2015

 

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

$

39,755

 

 

$

57,510

 

 

$

111,718

 

 

$

112,315

 

Changes in working capital

 

13,864

 

 

 

9,129

 

 

 

2,138

 

 

 

(3,145

)

Interest expense, net

 

27,910

 

 

 

18,037

 

 

 

56,728

 

 

 

34,115

 

Gain (loss) on interest rate swaps

 

(644

)

 

 

(776

)

 

 

(3,085

)

 

 

(1,091

)

Cash settlements paid on interest rate derivative instruments

 

1,272

 

 

 

512

 

 

 

2,160

 

 

 

643

 

Amortization of deferred financing fees

 

(1,256

)

 

 

(862

)

 

 

(3,116

)

 

 

(1,701

)

Accretion of senior notes discount

 

(605

)

 

 

(372

)

 

 

(1,204

)

 

 

(739

)

Acquisition related expenses

 

297

 

 

 

1,093

 

 

 

1,596

 

 

 

2,987

 

Income tax expense (benefit) - current portion

 

142

 

 

 

 

 

 

142

 

 

 

75

 

Exploration costs

 

32

 

 

 

204

 

 

 

122

 

 

 

210

 

Plugging and abandonment cost

 

2,108

 

 

 

 

 

 

2,108

 

 

 

 

Provision for environmental remediation

 

 

 

 

 

 

 

 

 

 

2,852

 

Adjusted EBITDA

$

82,875

 

 

$

84,475

 

 

$

169,307

 

 

$

146,521

 

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our Recast Form 8-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 and six months ended June 30, 2015 and 2014 have been derived from both our consolidated financial statements and the previous owners’ combined financial statements. The combined financial statements of the previous owners reflect the Memorial Resource assets that we acquired in February 2015. The results of operations for the three and six months ended June 30, 2014 have been recast for this acquisition, which closed in February 2015.

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

 

 

For the Six Months Ended

 

 

June 30,

 

 

June 30,

 

 

2015

 

 

2014

 

 

2015

 

 

2014

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil & natural gas sales

$

97,221

 

 

$

142,870

 

 

$

189,170

 

 

$

258,847

 

Pipeline tariff income and other

 

917

 

 

 

1,338

 

 

 

1,786

 

 

 

2,246

 

Total revenues

 

98,138

 

 

 

144,208

 

 

 

190,956

 

 

 

261,093

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

44,888

 

 

 

27,528

 

 

 

85,366

 

 

 

57,648

 

Pipeline operating

 

500

 

 

 

676

 

 

 

946

 

 

 

1,165

 

Gathering, processing and transportation

 

9,048

 

 

 

7,591

 

 

 

17,268

 

 

 

13,154

 

Exploration

 

32

 

 

 

204

 

 

 

122

 

 

 

210

 

Production and ad valorem taxes

 

6,058

 

 

 

7,418

 

 

 

12,713

 

 

 

13,429

 

Depreciation, depletion and amortization

 

46,286

 

 

 

42,966

 

 

 

97,552

 

 

 

75,516

 

Impairment of proved oil and natural gas properties

 

 

 

 

 

 

 

251,347

 

 

 

 

General and administrative

 

14,377

 

 

 

11,372

 

 

 

28,888

 

 

 

22,112

 

Accretion of asset retirement obligations

 

1,686

 

 

 

1,400

 

 

 

3,320

 

 

 

2,791

 

(Gain) loss on commodity derivative instruments

 

61,403

 

 

 

138,346

 

 

 

(84,056

)

 

 

185,112

 

Other, net

 

(943

)

 

 

 

 

 

(943

)

 

 

(12

)

Total costs and expenses

 

183,335

 

 

 

237,501

 

 

 

412,523

 

 

 

371,125

 

Operating income (loss)

 

(85,197

)

 

 

(93,293

)

 

 

(221,567

)

 

 

(110,032

)

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net

 

(27,910

)

 

 

(18,037

)

 

 

(56,728

)

 

 

(34,115

)

Other income (expense)

 

124

 

 

 

 

 

 

284

 

 

 

 

Total other income (expense)

 

(27,786

)

 

 

(18,037

)

 

 

(56,444

)

 

 

(34,115

)

Income before income taxes

 

(112,983

)

 

 

(111,330

)

 

 

(278,011

)

 

 

(144,147

)

Income tax benefit (expense)

 

(876

)

 

 

(310

)

 

 

1,494

 

 

 

(385

)

Net income (loss)

 

(113,859

)

 

 

(111,640

)

 

 

(276,517

)

 

 

(144,532

)

Net income (loss) attributable to noncontrolling interest

 

65

 

 

 

(12

)

 

 

224

 

 

 

43

 

Net income (loss) attributable to Memorial Production Partners LP

$

(113,924

)

 

$

(111,628

)

 

$

(276,741

)

 

$

(144,575

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas revenue:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil sales

$

52,815

 

 

$

62,373

 

 

$

97,068

 

 

$

105,119

 

NGL sales

 

11,213

 

 

 

19,515

 

 

 

23,336

 

 

 

36,794

 

Natural gas sales

 

33,193

 

 

 

60,982

 

 

 

68,766

 

 

 

116,934

 

Total oil and natural gas revenue

$

97,221

 

 

$

142,870

 

 

$

189,170

 

 

$

258,847

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

1,014

 

 

 

632

 

 

 

2,035

 

 

 

1,095

 

NGLs (MBbls)

 

692

 

 

 

617

 

 

 

1,391

 

 

 

1,109

 

Natural gas (MMcf)

 

12,322

 

 

 

12,968

 

 

 

24,703

 

 

 

24,052

 

Total (MMcfe)

 

22,548

 

 

 

20,457

 

 

 

45,246

 

 

 

37,272

 

Average net production (MMcfe/d)

 

247.8

 

 

 

224.8

 

 

 

250.0

 

 

 

205.9

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average sales price:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

$

52.09

 

 

$

98.76

 

 

$

47.70

 

 

$

96.02

 

NGL (per Bbl)

 

16.20

 

 

 

31.65

 

 

 

16.78

 

 

 

33.19

 

Natural gas (per Mcf)

 

2.69

 

 

 

4.70

 

 

 

2.78

 

 

 

4.86

 

Total (Mcfe)

$

4.31

 

 

$

6.98

 

 

$

4.18

 

 

$

6.94

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average unit costs per Mcfe:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expense

$

1.99

 

 

$

1.35

 

 

$

1.89

 

 

$

1.55

 

Gathering, processing and transportation

$

0.40

 

 

$

0.37

 

 

$

0.38

 

 

$

0.35

 

Production and ad valorem taxes

$

0.27

 

 

$

0.36

 

 

$

0.28

 

 

$

0.36

 

General and administrative expenses

$

0.64

 

 

$

0.56

 

 

$

0.64

 

 

$

0.59

 

Depletion, depreciation and amortization

$

2.05

 

 

$

2.10

 

 

$

2.16

 

 

$

2.03

 

 

31


 

Three Months Ended June 30, 2015 Compared to the Three Months Ended June 30, 2014

A net loss of $113.9 million was recorded during the three months ended June 30, 2015, primarily due to significant losses on commodity derivative instruments, compared to a net loss of $111.6 million recorded during the three months ended June 30, 2014.

·

Oil, natural gas and NGL revenues for 2015 totaled $97.2 million, a decrease of $45.7 million compared with 2014. Production increased 2.1 Bcfe (approximately 10%), primarily from increased drilling activities and increased volumes from third party acquisitions. The average realized sales price decreased $2.67 per Mcfe primarily due to lower period-to-period commodity prices. Crude oil volumes comprised approximately 27% of total volumes for 2015 compared to approximately 19% of total volumes for 2014.  The favorable volume variance and an unfavorable pricing variance contributed to an approximate $14.6 million increase and $60.3 million decrease in revenues, respectively.

·

Lease operating expenses were $44.9 million and $27.5 million during 2015 and 2014, respectively. On a per Mcfe basis, lease operating expenses were $1.99 for the three months ended June 30, 2015 compared to $1.35 for the three months ended June 30, 2014.  The increase was primarily due to the acquisition of oil properties with higher lifting costs and true-up of accruals.

·

Gathering, processing and transportation expenses were $9.0 million and $7.6 million during 2015 and 2014, respectively.  On a per Mcfe basis, gathering, processing and transportation expenses were $0.40 for the three months ended June 30, 2015 compared to $0.37 for the three months ended June 30, 2014.

·

Production and ad valorem taxes during the three months ended June 30, 2015 totaled $6.1 million, a decrease of $1.4 million compared with 2014 primarily due to lower realized commodity prices. On a per Mcfe basis, production and ad valorem taxes decreased to $0.27 for 2015 compared to $0.36 for 2014 due to reduced production and ad valorem taxes as a result of lower realized commodity prices in East Texas, South Texas and the Permian, offset by higher production tax rates on a per Mcfe basis for production from our July 2014 Wyoming acquisition.

·

DD&A expense during 2015 was $46.3 million compared to $43.0 million during 2014, a $3.3 million increase primarily due to an increase in production volumes related to third party acquisitions and our drilling program. Increased production volumes caused DD&A expense to increase by an approximate $4.4 million and the change in the DD&A rate between periods caused DD&A expense to decrease by approximately $1.1 million.

·

General and administrative expenses during 2015 were $14.4 million and included $2.6 million of non-cash unit-based compensation expense and $0.3 million of acquisition-related costs. General and administrative expenses during 2014 totaled $11.4 million and included approximately $1.7 million of non-cash unit-based compensation expense and approximately $1.1 million of acquisition-related costs.  The $3.0 million period-to-period increase was primarily due to the acquisition of properties in the third quarter of 2014.

·

Net losses on commodity derivative instruments of $61.4 million were recognized during 2015, consisting of $54.4 million of cash settlement receipts offset by a $115.8 million decrease in the fair value of open positions. Net losses on commodity derivative instruments of $138.3 million were recognized during 2014, consisting of $7.9 million of cash settlement payments and a $130.4 million decrease 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 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 $27.9 million during the three months ended June 30, 2015, including losses on interest rate swaps of approximately $0.6 million, amortization of deferred financing fees of approximately $1.3 million, and accretion of net discount associated with our senior notes of $0.6 million. Interest expense, net totaled $18.0 million during 2014, including losses on interest rate swaps of approximately $0.8 million, amortization of deferred financing fees of approximately $0.9 million and accretion of net discounts associated with our senior notes of $0.4 million. The $9.9 million increase in interest expense is primarily due to the increase in outstanding borrowings under our revolving credit facility and a higher aggregate principal amount of our senior notes issued and outstanding during 2015 compared to 2014.

 

32


 

Average outstanding borrowings under our revolving credit facility were $627.0 million during the three months ended 2015 compared to $431.7 million during 2014. We had an average of $1.2 billion aggregate principal amount of our senior notes issued and outstanding during 2015 as compared to an average of $700.0 million aggregate principal amount of our senior notes issued and outstanding during 2014.

 

Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014

A net loss of $276.5 million was recorded during the six months ended June 30, 2015, primarily due to impairment charges which were partially offset by significant gains on commodity derivative instruments, compared to a net loss of $144.5 million recorded during the six months ended June 30, 2014.

·

Oil, natural gas and NGL revenues for 2015 totaled $189.2 million, a decrease of $69.6 million compared with 2014. Production increased 8.0 Bcfe (approximately 21%), primarily from increased drilling activities and increased volumes from third party acquisitions. The average realized sales price decreased $2.76 per Mcfe primarily due to lower period-to-period commodity prices. Crude oil volumes comprised approximately 27% of total volumes for the six months ended June 30, 2015 compared to approximately 18% of total volumes for the six months ended June 30, 2014.  The favorable volume variance and an unfavorable pricing variance contributed to an approximate $55.3 million increase and $124.9 million decrease in revenues, respectively.

·

Lease operating expenses were $85.4 million and $57.6 million during 2015 and 2014, respectively. On a per Mcfe basis, lease operating expenses were $1.89 for 2015 compared to $1.55 for 2014.  The increase was primarily due to acquisition of oil properties with higher lifting costs.

·

Gathering, processing and transportation expenses were $17.3 million and $13.2 million during 2015 and 2014, respectively.  On a per Mcfe basis, gathering, processing and transportation expenses were $0.38 for the six months ended June 30, 2015 compared to $0.35 for June 30, 2014.

·

Production and ad valorem taxes during the six months ended June 30, 2015 totaled $12.7 million, a decrease of $0.7 million compared with the six months ended June 30, 2014 primarily due to a decrease in commodity prices. On a per Mcfe basis, production and ad valorem taxes decreased to $0.28 for 2015 compared to $0.36 for 2014 due to lower realized commodity prices in East Texas, South Texas and the Permian, partially offset by higher production tax rates on a per Mcfe basis for production from our July 2014 Wyoming acquisition.

·

DD&A expense during 2015 was $97.6 million compared to $75.5 million during 2014, a $22.1 million increase primarily due to both an increase in the depletable cost base and increased production volumes related to third party acquisitions and our drilling program. Increased production volumes caused DD&A expense to increase by an approximate $16.2 million and the change in the DD&A rate between periods caused DD&A expense to increase by approximately $5.9 million.

·

We recognized $251.3 million of impairments during the six months ended June 30, 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 due to declining commodity prices.  We did not record any impairments during 2014.

·

General and administrative expenses during 2015 were $28.9 million and included $4.9 million of non-cash unit-based compensation expense and $1.6 million of acquisition-related costs. General and administrative expenses during 2014 totaled $22.1 million and included approximately $3.0 million of non-cash unit-based compensation expense and approximately $3.0 million of acquisition-related costs. Increased salaries and employee headcount also contributed to increased general and administrative expenses during the period.  The $6.8 million period-to-period increase was primarily due to the acquisition of properties in the third quarter of 2014.

·

Net gains on commodity derivative instruments of $84.1 million were recognized during the six months ended June 30, 2015, consisting of $114.4 million of cash settlement receipts on expired positions and $27.1 million in cash settlements received on terminated derivatives.  These gains were offset by a $57.4 million decrease in the fair value of open positions. Net losses on commodity derivative instruments of $185.1 million were recognized during the six months ended June 30, 2014, consisting of $15.9 million of cash settlement payments and a $169.2 million decrease in the fair value of open positions.

33


 

·

Net interest expense is comprised of interest on our 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 $56.7 million during the six months ended June 30, 2015, including losses on interest rate swaps of approximately $3.1 million, amortization of deferred financing fees of approximately $3.1 million, and accretion of net discount associated with our senior notes of $1.2 million. Interest expense, net totaled $34.1 million during 2014, including losses on interest rate swaps of approximately $1.1 million, amortization of deferred financing fees of approximately $1.7 million and accretion of net discounts associated with our senior notes of $0.7 million. The $22.6 million increase in interest expense is primarily due to the increase in outstanding borrowings under our revolving credit facility and a higher aggregate principal amount of our senior notes issued and outstanding during 2015 compared to 2014.

 

Average outstanding borrowings under our revolving credit facility were $567.9 million during 2015 compared to $291.0 million during 2014. We had an average of $1.2 billion aggregate principal amount of our senior notes issued and outstanding during the six months ended June 30, 2015 as compared to an average of $700.0 million aggregate principal amount of our senior notes issued and outstanding during the six months ended June 30, 2014.

 

Liquidity and Capital Resources

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 ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for oil, natural gas, and NGL, and our ongoing efforts to manage production volumes, operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.

As of June 30, 2015, we had approximately $653.2 million of available borrowing capacity under our revolving credit facility, which is net of $4.8 million in letters of credit. We had $0.2 million of cash and cash equivalents as of June 30, 2015. On March 24, 2015, our borrowing base decreased from $1.44 billion to $1.3 billion in connection with its semi-annual redetermination.  Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our revolving credit facility. 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.  We have also filed a shelf registration statement with the SEC which will allow us to issue from time to time up to $250 million in aggregate of 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.

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 June 30, 2015, we had a working capital balance of $103.5 million primarily due to a net asset balance of $169.7 million of current derivative instruments partially offset by the timing of accruals, which included accrued capital expenditures of $37.5 million and accrued interest payable of $27.1 million.

Capital Expenditures

For the six months ended June 30, 2015, our total capital expenditures, including unproved additions, were approximately $131.1 million, substantially all of which were related to drilling, recompletions and capital workovers.

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 June 30, 2015, we had $642.0 million of outstanding borrowings and $4.8 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 June 30, 2015, we believe we were in compliance with all of the financial and other covenants under our revolving credit facility.

34


 

For additional information regarding our revolving credit facility, see Note 8 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

2022 Senior Notes

As of June 30, 2015, 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 an indenture dated as of July 17, 2014.  In January 2015, we repurchased an aggregate 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 and recognized a gain of approximately $0.4 million.  

For additional information regarding the 2022 Senior Notes, see Note 8 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

2021 Senior Notes

As of June 30, 2015, 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 the 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 an indenture dated as of April 17, 2013.

For additional information regarding the 2021 Senior Notes, see Note 8 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

Commodity Derivative Contracts

Our hedging policy is designed to reduce the impact to our cash flows from commodity price volatility. Under this policy, we intend to enter into commodity derivative contracts covering approximately 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. Our revolving credit facility contains various covenants and restrictive provisions which, among other things, limit our ability to enter into commodity price hedges exceeding a certain percentage of production. It has been our practice to enter into costless collars and fixed price swaps primarily with lenders under our credit agreement. Historically, the Partnership has not paid or received premiums for 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.

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 June 30, 2015, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk.”

Interest Rate Derivative Contracts

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. 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 “Item 3. Quantitative and Qualitative Disclosure About Market Risk” for a summary of our derivative contracts as of June 30, 2015.

35


 

Counterparty Exposure

Our derivative contracts are primarily with major financial institutions, certain of which are also lenders under our revolving credit facility. We have rights of offset against the borrowings under our revolving credit facility. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk” for additional information.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the six months ended June 30, 2015 and 2014 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 Six Months Ended

 

 

 

June 30,

 

 

 

2015

 

 

2014

 

Net cash provided by operating activities

 

$

111,718

 

 

$

112,315

 

Net cash used in investing activities

 

 

127,666

 

 

 

383,451

 

Net cash provided by financing activities

 

 

15,141

 

 

 

255,995

 

 

Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities decreased by $0.6 million and net income decreased by $132.0 million. Production increased 8.0 Bcfe (approximately 21%) while average realized sales price decreased $2.76 per Mcfe. Net cash provided by operating activities included a $128.8 million period-to-period increase in cash settlements received on expired commodity derivative instruments partially offset by a $5.3 million period-to-period decrease in cash flow attributable to the timing of cash receipts and disbursements related to operating activities. These period-to-period increases partially offset decreased revenues and increased operating costs as previously discussed under “—Results of Operations.”

Investing Activities. Net cash used in investing activities during 2015 was $127.7 million, of which $6.1 million was used to acquire oil and natural gas properties from a third party and $128.3 million was used for additions to oil and natural gas properties. Net cash used in investing activities during 2014 was $383.5 million, of which $173.0 million was used to acquire oil and natural gas properties from a third party and $138.2 million was used for additions to oil and natural gas properties. In May 2014, we paid a deposit of $70.1 million related to the Wyoming Acquisition.  We received a post-closing settlement receipt of $9.6 million related to the Wyoming Acquisition during 2015.  Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our offshore Southern California oil and natural gas properties.  Additions to restricted investments were $2.7 million during the six months ended June 30, 2015 compared to $2.1 million during the six months ended June 30, 2014.

Financing Activities. Distributions to partners during 2015 were $92.6 million compared to $67.5 million during 2014. The increase is due to an increase in the number of outstanding units between periods. We paid $78.4 million to Memorial Resource in connection with the Property Swap as previously discussed under “—Recent Developments.”  We paid Memorial Resource $33.9 million related to the acquisition of certain assets in East Texas during 2014.  Capital contributions received from the previous owners were $1.9 million and $2.0 million during 2015 and 2014, respectively.

The Partnership had net borrowings of $230.0 million under its revolving credit facility during 2015 that were primarily used to fund the Property Swap and to fund its drilling program. The Partnership had net borrowings of $356.0 million under its revolving credit facility during 2014 that were used primarily to fund its March 2014 Eagle Ford acquisition, the deposit for the Wyoming Acquisition and its drilling program.

We repurchased $42.6 million in common units during 2015, which represents a repurchase and retirement of 2,862,782 common units under the MEMP Repurchase Program (including common unit repurchases of $1.4 million, representing 93,800 common units, accrued at December 31, 2014).  In addition, we accrued repurchases of $2.7 million, representing 182,630 common units at June 30, 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 2014, 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.

36


 

Contractual Obligations

During the six months ended June 30, 2015, there were no significant changes since those reported in our Recast Form 8-K.

Off–Balance Sheet Arrangements

As of June 30, 2015, 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 Item 1 of this quarterly report.

 

 

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 2014 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 enter into costless collars and fixed price swaps only with lenders under our credit agreement. Historically, the Partnership has not paid or received premiums for 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.

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 June 30, 2015, see Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

Interest Rate Risk

Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. See Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report for interest rate swap arrangements that were outstanding at June 30, 2015.

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 any discount or premium) is compared to the estimated fair value in the table below (in thousands):  

 

 

 

June 30, 2015

 

 

 

Carrying

 

 

Estimated

 

Description

 

Amount

 

 

Fair Value

 

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

 

$

691,296

 

 

$

669,375

 

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

 

 

490,354

 

 

$

454,746

 

 

37


 

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 June 30, 2015, after taking into effect netting arrangements, we had counterparty exposure of $199.7 million related to our derivative instruments. As a result, had all counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $286.1 million against amounts outstanding under our revolving credit facility at June 30, 2015.

ITEM 4.

CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

As required by Rules 13a-15(b) and 15d-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer of our general partner, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) and under the Exchange Act) as of the end of the period covered by this 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 June 30, 2015.

Change in Internal Controls Over Financial Reporting

No changes in our internal control over financial reporting occurred during the quarter ended June 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

 

 

 

38


 

PART II—OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS.

For information regarding legal proceedings, see Part I, Item 1, Financial Statements, Note 13, “Commitments and Contingencies – Litigation & Environmental,” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included in this quarterly report, which is incorporated herein by reference.

ITEM 1A.

RISK FACTORS.

Our business faces many risks. Any of the risks discussed elsewhere in this Quarterly Report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. 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, 2014 filed with the SEC on February 26, 2015 and our Quarterly Report on Form 10-Q for the three months ended March 31, 2015 filed with the SEC on May 8, 2015.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

Our general partner’s 0.1% interest in us was represented by 86,797 general partner units at June 30, 2015. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its current general partner interest.

The following table summarizes our repurchase activity during the quarterly period ended June 30, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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)

 

Repurchase Program (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

April 1, 2015 - April 30, 2015

 

 

 

 

$

 

 

 

2,809,495

 

 

$

106,072

 

May 1, 2015 - May 31, 2015

 

 

612,961

 

 

$

14.86

 

 

 

3,422,456

 

 

$

96,966

 

June 1, 2015 - June 30, 2015

 

 

429,068

 

 

$

14.93

 

 

 

3,851,524

 

 

$

90,562

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted Unit Repurchases (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

April 1, 2015 - April 30, 2015

 

 

 

 

$

 

 

n/a

 

 

n/a

 

May 1, 2015 - May 31, 2015

 

 

85,087

 

 

$

14.94

 

 

n/a

 

 

n/a

 

June 1, 2015 - June 30, 2015

 

 

510

 

 

$

15.15

 

 

n/a

 

 

n/a

 

 

 

(1)

Represents common units repurchased under the MEMP Repurchase Program.  See Note 9 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

(2)

Restricted common units are generally net-settled by unitholders to cover the required withholding tax upon vesting.  See Note 9 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4.

MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5.

OTHER INFORMATION.

None.

39


 

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.

 

 

 

40


 

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: August 5, 2015

By:

 

/s/ Robert L. Stillwell, Jr.

 

Name:

 

Robert L. Stillwell, Jr.

 

Title:

 

Vice President and Chief  Financial Officer of

 

 

 

Memorial Production Partners GP LLC

 

 

41


 

EXHIBIT INDEX

Exhibit
Number

 

 

 

Description

 

 

 

   2.1##

 

 

Purchase and Sale Agreement, dated as of March 25, 2014, between Alta Mesa Eagle, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on March 25, 2014).

 

 

 

 

 

   2.2##

 

 

Purchase and Sale Agreement, dated as of May 2, 2014, among Merit Management Partners I, L.P., Merit Energy Partners III, L.P., Merit Pipeline Company, LLC, Merit Energy Company, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on May 5, 2014).

 

 

 

 

 

   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).

 

 

 

 

 

   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.

 

 

 

42