Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

(Mark One)

 

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

 

For the quarterly period ended March 31, 2015

 

OR

 

o         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:  001-35344

 

LRR Energy, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware

 

90-0708431

(State or other jurisdiction of
incorporation or organization)

 

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

 

Heritage Plaza

 

 

1111 Bagby, Suite 4600

 

 

Houston, Texas

 

77002

(Address of principal executive offices)

 

(Zip code)

 

Telephone Number:  (713) 292-9510

(Registrant’s telephone number, including area code)

 


 

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  x   No  o

 

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  x  No  o

 

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer o

 

Accelerated filer x

 

 

 

Non-accelerated filer o

 

Smaller reporting company o

(Do not check if a 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  o  No  x

 

There were 28,074,433 Common Units and 22,400 General Partner Units outstanding as of May 1, 2015.  The Common Units trade on the New York Stock Exchange under the ticker symbol “LRE”.

 

 

 



Table of Contents

 

LRR Energy, L.P.

 

TABLE OF CONTENTS

 

 

Caption

 

Page

 

 

 

 

 

PART I — FINANCIAL INFORMATION

 

 

 

 

 

 

Item 1.

Financial Statements.

 

 

 

Unaudited Consolidated Condensed Balance Sheets as of March 31, 2015 and December 31, 2014

 

1

 

Unaudited Consolidated Condensed Statements of Operations for the Three Months Ended March 31, 2015 and 2014

 

2

 

Unaudited Consolidated Condensed Statement of Changes in Unitholders’ Equity as of March 31, 2015

 

3

 

Unaudited Consolidated Condensed Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014

 

4

 

Notes to Unaudited Consolidated Condensed Financial Statements

 

5

Item 2.

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

 

19

Item 3.

Quantitative and Qualitative Disclosures About Market Risk.

 

28

Item 4.

Controls and Procedures.

 

28

 

 

 

 

 

PART II — OTHER INFORMATION

 

 

 

 

 

 

Item 1.

Legal Proceedings.

 

29

Item 1A.

Risk Factors.

 

29

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds.

 

30

Item 3.

Defaults Upon Senior Securities.

 

30

Item 4.

Mine Safety Disclosures.

 

30

Item 5.

Other Information.

 

30

Item 6.

Exhibits.

 

30

 

Signatures.

 

32

 

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PART I—FINANCIAL INFORMATION

 

Item 1. Financial Statements.

 

LRR Energy, L.P.

Consolidated Condensed Balance Sheets

(Unaudited)

(in thousands, except unit amounts)

 

 

 

March 31, 2015

 

December 31, 2014

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

2,740

 

$

3,576

 

Accounts receivable

 

9,450

 

11,124

 

Commodity derivative instruments

 

43,368

 

45,924

 

Due from affiliates

 

6,351

 

5,697

 

Prepaid expenses

 

1,672

 

1,840

 

Total current assets

 

63,581

 

68,161

 

Property and equipment (successful efforts method)

 

963,400

 

956,326

 

Accumulated depletion, depreciation and impairment

 

(550,942

)

(506,368

)

Total property and equipment, net

 

412,458

 

449,958

 

Commodity derivative instruments

 

46,454

 

38,540

 

Deferred financing costs, net of accumulated amortization and other assets

 

2,295

 

2,295

 

TOTAL ASSETS

 

$

524,788

 

$

558,954

 

LIABILITIES AND UNITHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accrued liabilities

 

$

3,613

 

$

5,506

 

Accrued capital cost

 

3,801

 

9,176

 

Commodity derivative instruments

 

866

 

556

 

Interest rate derivative instruments

 

2,750

 

2,327

 

Asset retirement obligations

 

1,079

 

1,065

 

Total current liabilities

 

12,109

 

18,630

 

Long-term liabilities:

 

 

 

 

 

Commodity derivative instruments

 

116

 

232

 

Interest rate derivative instruments

 

1,340

 

817

 

Term loan

 

50,000

 

50,000

 

Revolving credit facility

 

240,000

 

230,000

 

Asset retirement obligations

 

41,053

 

40,539

 

Deferred tax liabilities

 

99

 

99

 

Total long-term liabilities

 

332,608

 

321,687

 

Total liabilities

 

344,717

 

340,317

 

Unitholders’ equity:

 

 

 

 

 

General partner (22,400 units issued and outstanding as of March 31, 2015 and December 31, 2014)

 

(1,540

)

310

 

Public common unitholders (19,504,833 units issued and outstanding as of March 31, 2015 and 19,492,291 units issued and outstanding as of December 31, 2014)

 

181,611

 

208,273

 

Affiliated common unitholders (8,569,600 units issued and outstanding as of March 31, 2015 and 4,089,600 units issued and outstanding as of December 31, 2014)

 

 

4,643

 

Subordinated unitholders (4,480,000 units issued and outstanding as of December 31, 2014)

 

 

5,411

 

Total unitholders’ equity

 

180,071

 

218,637

 

TOTAL LIABILITIES AND UNITHOLDERS’ EQUITY

 

$

524,788

 

$

558,954

 

 

See accompanying notes to the unaudited consolidated condensed financial statements.

 

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Table of Contents

 

LRR Energy, L.P.

Consolidated Condensed Statements of Operations

(Unaudited)

(in thousands, except per unit amounts)

 

 

 

Three Months Ended March 31,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

Oil sales

 

$

12,064

 

$

20,156

 

Natural gas sales

 

4,266

 

8,099

 

Natural gas liquids sales

 

1,171

 

3,364

 

Gain (loss) on commodity derivative instruments, net

 

18,682

 

(5,622

)

Other income

 

29

 

31

 

Total revenues

 

36,212

 

26,028

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

Lease operating expense

 

6,772

 

5,835

 

Production and ad valorem taxes

 

1,266

 

2,400

 

Depletion and depreciation

 

8,880

 

8,465

 

Impairment of oil and natural gas properties

 

35,706

 

 

Accretion expense

 

511

 

503

 

Loss (gain) on settlement of asset retirement obligations

 

64

 

40

 

General and administrative expense

 

3,791

 

3,182

 

Total operating expenses

 

56,990

 

20,425

 

 

 

 

 

 

 

Operating income (loss)

 

(20,778

)

5,603

 

 

 

 

 

 

 

Other income (expense), net

 

 

 

 

 

Interest expense

 

(2,769

)

(2,541

)

Gain (loss) on interest rate derivative instruments, net

 

(1,351

)

(294

)

Other income (expense), net

 

(4,120

)

(2,835

)

 

 

 

 

 

 

Income (loss) before taxes

 

(24,898

)

2,768

 

Income tax expense

 

(38

)

(74

)

Net income (loss) available to unitholders

 

$

(24,936

)

$

2,694

 

 

 

 

 

 

 

Computation of net income (loss) per limited partner unit:

 

 

 

 

 

 

 

 

 

 

 

General partner’s interest in net income (loss)

 

$

(1,839

)

$

3

 

 

 

 

 

 

 

Limited partners’ interest in net income (loss)

 

$

(23,097

)

$

2,691

 

 

 

 

 

 

 

Net income (loss) per limited partner unit (basic and diluted)

 

$

(0.82

)

$

0.10

 

 

 

 

 

 

 

Weighted average number of limited partner units outstanding (basic and diluted)

 

28,072

 

26,342

 

 

See accompanying notes to the unaudited consolidated condensed financial statements.

 

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Table of Contents

 

LRR Energy, L.P.

Consolidated Condensed Statement of Changes in Unitholders’ Equity

(Unaudited)

(in thousands)

 

 

 

 

 

Limited Partners

 

 

 

 

 

General

 

Public

 

Affiliated

 

 

 

 

 

Partner

 

Common

 

Common

 

Subordinated

 

Total

 

Balance, December 31, 2014

 

$

310

 

$

208,273

 

$

4,643

 

$

5,411

 

$

218,637

 

Equity offering, net of expenses

 

 

3

 

 

 

3

 

Amortization of equity awards

 

 

345

 

 

 

345

 

Conversion of subordinated units

 

 

 

3,182

 

(3,182

)

 

Distribution

 

(11

)

(9,704

)

(2,034

)

(2,229

)

(13,978

)

Net income (loss)

 

(1,839

)

(17,306

)

(5,791

)

 

(24,936

)

Balance, March 31, 2015

 

$

(1,540

)

$

181,611

 

$

 

$

 

$

180,071

 

 

See accompanying notes to the unaudited consolidated condensed financial statements.

 

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LRR Energy, L.P.

Consolidated Condensed Statements of Cash Flows

(Unaudited)

(in thousands)

 

 

 

Three Months Ended March 31,

 

 

 

2015

 

2014

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income (loss)

 

$

(24,936

)

$

2,694

 

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

 

 

 

 

 

Depletion and depreciation

 

8,880

 

8,465

 

Impairment of oil and natural gas properties

 

35,706

 

 

Accretion expense

 

511

 

503

 

Amortization of equity awards

 

345

 

285

 

Amortization of derivative contracts

 

114

 

157

 

Amortization of deferred financing costs and other

 

170

 

102

 

Loss (gain) on settlement of asset retirement obligations

 

64

 

40

 

Changes in operating assets and liabilities:

 

 

 

 

 

Change in receivables

 

1,674

 

(996

)

Change in prepaid expenses

 

(2

)

377

 

Change in derivative assets and liabilities

 

(4,331

)

6,082

 

Change in amounts due to/from affiliates

 

(654

)

(4,412

)

Change in accrued liabilities and deferred tax liabilities

 

(1,893

)

2,829

 

Net cash provided by (used in) operating activities

 

15,648

 

16,126

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Development of oil and natural gas properties

 

(12,280

)

(6,803

)

Acquisition of oil and natural gas properties

 

(229

)

 

Disposition of oil and natural gas properties

 

 

65

 

Net cash provided by (used in) investing activities

 

(12,509

)

(6,738

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Borrowings under revolving credit facility

 

10,000

 

10,000

 

Principal payments on revolving credit facility

 

 

(10,000

)

Equity offering, net of expenses

 

3

 

4,237

 

Distributions

 

(13,978

)

(12,884

)

Net cash provided by (used in) financing activities

 

(3,975

)

(8,647

)

 

 

 

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

 

(836

)

741

 

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD

 

3,576

 

4,417

 

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS, END OF PERIOD

 

$

2,740

 

$

5,158

 

 

See accompanying notes to the unaudited consolidated condensed financial statements.

 

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LRR Energy, L.P.

Notes to Consolidated Condensed Financial Statements

(unaudited)

 

1.              Organization and Description of Business

 

LRR Energy, L.P. (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed in April 2011 by Lime Rock Management LP (“Lime Rock Management”), an affiliate of Lime Rock Resources A, L.P. (“LRR A”), Lime Rock Resources B, L.P. (“LRR B”) and Lime Rock Resources C, L.P. (“LRR C”), to operate, acquire, exploit and develop producing oil and natural gas properties in North America with long-lived, predictable production profiles. As used herein, references to “Fund I” refer collectively to LRR A, LRR B and LRR C; references to “Fund II” refer collectively to Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P.; and references to “Fund III” refer collectively to Lime Rock Resources III-A, L.P. and Lime Rock Resources III-C, L.P. References to “Lime Rock Resources” refer collectively to Fund I, Fund II and Fund III.

 

Our properties are located in the Permian Basin region in West Texas and Southeast New Mexico, the Mid-Continent region in Oklahoma and East Texas and the Gulf Coast region in Texas. We conduct our operations through our wholly owned subsidiary, LRE Operating, LLC (“OLLC”).

 

We own 100% of LRE Finance Corporation (“LRE Finance”). LRE Finance was organized for the purpose of co-issuing our debt securities and has no material assets or liabilities other than as co-issuer of our debt securities, if and when issued. Its activities are limited to co-issuing our debt securities and engaging in activities related thereto.

 

2.              Summary of Significant Accounting Policies

 

Our accounting policies are set forth in the audited consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2014 (“2014 Annual Report”) and are supplemented by the notes to these unaudited consolidated condensed financial statements. There have been no significant changes to these policies, and these unaudited consolidated condensed financial statements should be read in conjunction with the audited consolidated financial statements and notes in our 2014 Annual Report.

 

Basis of presentation

 

These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements and should be read in conjunction with the audited consolidated financial statements in our 2014 Annual Report. While the year-end condensed balance sheet data was derived from audited financial statements, this interim report does not include all disclosures required by GAAP for annual periods. These unaudited interim consolidated condensed financial statements reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for the periods presented.

 

Recent accounting pronouncements

 

On April 10, 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” ASU 2014-08 amends the definition of a discontinued operation and requires entities to provide additional disclosures about discontinued operations as well as disposal transactions that do not meet the discontinued-operations criteria. We adopted ASU 2014-08 on January 1, 2015. The adoption of ASU 2014-08 did not have a material impact on our consolidated condensed financial position, results of operations or cash flows.

 

On May 28, 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers.” ASU No. 2014-09 outlined a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the revenue model is

 

5



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that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 is effective for annual reporting periods beginning after December 15, 2016 and early adoption is not permitted. We are still evaluating the impact of our adoption of ASU No. 2014-09.

 

On August 27, 2014, the FASB issued ASU 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” ASU No. 2014-15 provides guidance on determining when and how reporting entities must disclose going-concern uncertainties in their financial statements. The new standard requires management to perform interim and annual assessments of an entity’s financial statements (or within one year after the date on which the financial statements are available to be issued, when applicable). Further, an entity must provide certain disclosures if there is “substantial doubt about the entity’s ability to continue as a going concern.” ASU No. 2014-15 is effective for annual periods ending after December 15, 2016, and interim periods thereafter; early adoption is permitted. We do not expect the adoption of ASU No. 2014-15 to have a material impact on our financial statement disclosures.

 

On February 18, 2015, the FASB issued ASU 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis.” ASU No. 2015-02 applies to entities in all industries and provides a new scope exception to registered money market funds and similar unregistered money market funds. The standard makes targeted amendments to the current consolidation guidance and ends the deferral granted to investment companies from applying the variable interest entities guidance. ASU No. 2015-02 is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. We are still evaluating the impact of our adoption of ASU No. 2015-02.

 

On April 7, 2015, the FASB issued ASU 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” ASU No. 2015-03 changes the presentation of debt issuance costs in financial statements. The new standard requires entities to present debt issuance costs as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs is reported as interest expense. ASU No. 2015-03 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, and interim periods beginning after December 15, 2016. Early adoption is allowed for all entities for financial statements that have not been previously issued. Entities would apply the new guidance retrospectively to all prior periods. We do not expect the adoption of ASU No. 2015-03 to have a material impact on our financial statements or disclosures.

 

3.              Acquisitions

 

Third Party Acquisition

 

On October 1, 2014, we completed an acquisition of oil and natural gas properties in the Stroud field located in Lincoln and Creek Counties, Oklahoma for a purchase price of $38.0 million, subject to customary purchase price adjustments (the “October 2014 Acquisition”) from an unrelated third party. We paid total cash consideration of $38.2 million at closing. The October 2014 Acquisition was effective September 1, 2014. In January 2015, we paid $0.2 million in cash to the seller related to post-closing adjustments to the purchase price. We financed the acquisition with borrowings under our revolving credit facility (Note 7).

 

The October 2014 Acquisition was accounted for under the acquisition method of accounting, whereby the purchase price was allocated to the assets acquired and liabilities assumed based on their fair values, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill (or shortfall of purchase price versus net fair value recorded as bargain purchase). Based on the purchase price allocation for October 2014 Acquisition, no goodwill or bargain purchase was recognized. The cash consideration paid for the October 2014 Acquisition and the assets and liabilities recognized are presented in the table below (in thousands, except for per unit amounts):

 

Property and equipment, net

 

$

38,848

 

Asset retirement obligations

 

(691

)

Net assets

 

$

38,157

 

 

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The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) reserves, including risk adjustments for probable and possible reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; (v) future cash flows; and (vi) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by our management at the time of the valuation and are subject to change.

 

The following unaudited pro forma information shows the pro forma effects of the October 2014 Acquisition. The unaudited pro forma information assumes the transaction occurred on January 1, 2014. The pro forma results of operations have been prepared by adjusting our historical results to include the historical results of the acquired assets based on information provided by the seller, our knowledge of the acquired properties and the impact of our purchase price allocation. We believe the assumptions used provide a reasonable basis for reflecting the pro forma significant effects directly attributable to the acquisition. The pro forma results of operations do not include any cost savings or other synergies that may result from the October 2014 Acquisition or any estimated costs that have been or will be incurred to integrate the assets. The following unaudited pro forma information does not purport to represent what our results of operations would have been if such acquisition had occurred on January 1, 2014 (in thousands).

 

 

 

Three Months Ended

 

 

 

March 31, 2014

 

Total revenues

 

$

28,343

 

Net income (loss) available to unitholders

 

3,997

 

Basic and diluted net income (loss) per unit

 

0.15

 

 

4.              Fair Value Measurements

 

Our financial instruments, including cash and cash equivalents and accounts receivable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. All such financial instruments are considered Level 1 instruments. The carrying value of our senior secured revolving credit facility and term loan, including the current portion, approximates fair value, as interest rates are variable based on prevailing market rates and are therefore considered Level 1 instruments. Our financial and non-financial assets and liabilities that are measured on a recurring basis are measured and reported at fair value.

 

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 the measurement date. GAAP establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of fair value hierarchy are as follows:

 

Level 1—Defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities.

 

Level 2—Defined as inputs other than quoted prices in active markets that are either directly or indirectly observable for the asset or liability.

 

Level 3—Defined as unobservable inputs for use when little or no market data exists, requiring an entity to develop its own assumptions for the asset or liability.

 

We utilize the most observable inputs available for the valuation technique used. The financial assets and liabilities are classified in their entirety based on the lowest level of input that is of significance to the fair value measurement. The following table describes, by level within the hierarchy, the fair value of our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2015 and December 31, 2014 (in thousands).

 

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Level 1

 

Level 2

 

Level 3

 

Total

 

March 31, 2015

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

$

 

$

89,822

 

$

 

$

89,822

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

 

982

 

 

982

 

Interest rate derivative instruments

 

 

4,090

 

 

4,090

 

December 31, 2014

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

$

 

$

84,464

 

$

 

$

84,464

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

 

788

 

 

788

 

Interest rate derivative instruments

 

 

3,144

 

 

3,144

 

 

All fair values reflected in the table above and on the consolidated condensed balance sheets have been adjusted for non-performance risk. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

 

Commodity Derivative Instruments—The fair value of the commodity derivative instruments is estimated using a combined income and market valuation methodology based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.

 

Interest Rate Derivative Instruments—The fair value of the interest rate derivative instruments is estimated using a combined income and market valuation methodology based upon forward interest rates and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.

 

5.              Property and Equipment

 

Property and equipment is stated at cost less accumulated depletion, depreciation and impairment and consisted of the following (in thousands):

 

 

 

March 31, 2015

 

December 31, 2014

 

Oil and natural gas properties (successful efforts method)

 

$

961,907

 

$

954,819

 

Unproved properties

 

1,221

 

1,235

 

Other property and equipment

 

272

 

272

 

 

 

963,400

 

956,326

 

Accumulated depletion, depreciation and impairment

 

(550,942

)

(506,368

)

Total property and equipment, net

 

$

412,458

 

$

449,958

 

 

We recorded $8.9 million and $8.5 million of depletion and depreciation expense for the three months ended March 31, 2015 and 2014, respectively.

 

We perform an impairment analysis of our oil and natural gas properties on a quarterly basis due to the volatility in commodity prices. For the three months ended March 31, 2015, we recorded a total non-cash impairment charge of $35.7 million to impair the value of our proved oil and natural gas properties in the Permian Basin, Gulf Coast, and the Mid-Continent regions. This impairment charge reduced the regions’ carrying values to an estimated fair value of $411.2 million as of March 31, 2015. We did not record any impairment charges in the three months ended March 31, 2014.

 

These impairments of proved and unproved oil and natural gas properties were recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash flows reported in an internal reserve report. Further, our unproved properties were impaired based on the drilling locations

 

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for the probable and possible reserves becoming uneconomic at the lower future expected natural gas prices and our future expected drilling schedules. These reports are based upon future oil and natural gas prices, which are based on observable inputs, adjusted for basis differentials. These are classified as Level 3 fair value measurements. The fair values of our properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of the properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the our estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. Furthermore, significant assumptions in valuing the proved reserves included the reserve quantities, anticipated drilling and operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated drilling schedules, anticipated production declines, and an appropriate discount rate commensurate with the risk of the underlying cash flow estimates. Cash flow estimates for the impairment testing excluded derivative instruments used to mitigate the risk of lower future natural gas prices. Significant assumptions in valuing the unproved reserves included the evaluation of the probable and possible reserves, future expected natural gas prices and basis differentials, and anticipated drilling schedules.

 

These asset impairments have no impact on cash flows, liquidity positions, or debt covenants. If future oil or natural gas prices decline, the estimated undiscounted future cash flows for the proved oil and natural gas properties may not exceed the net capitalized costs for our properties and a non-cash impairment charge may be required to be recognized in future periods.

 

6.              Asset Retirement Obligations

 

The following is a summary of our asset retirement obligations as of and for the three months ended March 31, 2015 (in thousands):

 

Beginning of period

 

$

41,604

 

Acquisitions

 

14

 

Revisions to previous estimates

 

5

 

Liabilities settled

 

(2

)

Accretion expense

 

511

 

End of period

 

42,132

 

Current portion of asset retirement obligations

 

(1,079

)

Asset retirement obligations — non-current

 

$

41,053

 

 

7.              Long-Term Debt

 

Credit Agreement

 

We, as guarantor, and our wholly owned subsidiary, OLLC, as borrower, are parties to a five-year, $750 million senior secured revolving credit facility, as amended (the “Credit Agreement”), that matures on October 1, 2019. The Intercreditor Agreement (as described below) limits the amount of indebtedness outstanding at any time under the Credit Agreement (including undrawn amounts under letters of credit) to an amount not to exceed $500 million in the aggregate. The Credit Agreement is reserve-based and we are permitted to borrow under our credit facility an amount up to the borrowing base, which was $260 million as of March 31, 2015. Our borrowing base, which is primarily based on the estimated value of our oil, natural gas liquids (“NGL”), and natural gas properties and our commodity derivative contracts, is subject to redetermination semi-annually by our lenders at their sole discretion. As of March 31, 2015, we were in compliance with all covenants contained in the Credit Agreement.

 

In the second quarter of 2015, primarily as a result of significantly lower commodity prices, our borrowing base was reduced to $245.0 million under an amendment to our Credit Agreement. Pursuant to the amendment, the borrowing base will decrease by $1.0 million per month beginning in June 2015 and continuing until the next borrowing base redetermination in November 2015. The amendment is discussed in Note 14.

 

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Term Loan Agreement

 

We, as parent guarantor, and our wholly owned subsidiary, OLLC, as borrower, are parties to a Second Lien Credit Agreement (the “Term Loan Agreement”). The Term Loan Agreement provides for a $50 million senior secured second lien term loan to OLLC. OLLC borrowed $50 million under the Term Loan Agreement and used the borrowings to repay outstanding borrowings under the Credit Agreement.

 

The Term Loan Agreement contains various covenants and restrictive provisions as described in our 2014 Annual Report. As of March 31, 2015, we were in compliance with the leverage and current ratios contained in our Term Loan Agreement. We are required to test the asset coverage ratio at specified intervals as described in the Term Loan Agreement, including during the redetermination of our borrowing base under our Credit Agreement. We were not in compliance with the asset coverage ratio during the borrowing base redetermination in the second quarter of 2015; however, we received a waiver from our lender under the Term Loan Agreement for the asset coverage ratio covenant.

 

The obligations under the Term Loan Agreement and the Credit Agreement are governed by an Intercreditor Agreement with OLLC as borrower and the Partnership as parent guarantor, which (i) provides that any liens on the assets and properties of OLLC, the Partnership or any of their subsidiaries securing the indebtedness under the Term Loan Agreement are subordinate to liens on the assets and properties of OLLC, the Partnership or any of their subsidiaries securing indebtedness under the Credit Agreement and derivative contracts with lenders and their affiliates and (ii) sets forth the respective rights, obligations and remedies of the lenders under the Credit Agreement with respect to their first-priority liens and the lenders under the Term Loan Agreement with respect to their second-priority liens.

 

As of March 31, 2015, we had $290.0 million of outstanding debt and accrued interest was approximately $0.2 million. As of December 31, 2014, we had $280.0 million of outstanding debt and accrued interest was approximately $0.2 million.

 

Interest expense for the three months ended March 31, 2015 and 2014 was $2.8 million and $2.5 million, respectively. As of March 31, 2015 and December 31, 2014, our weighted average interest rate on our outstanding indebtedness was 4.60% and 3.81%, respectively. Please refer to Note 8 below for a discussion of our interest rate derivative contracts.

 

8.              Derivatives

 

We are exposed to commodity price and interest rate risk and consider it prudent to periodically reduce our exposure to cash flow variability resulting from commodity price changes and interest rate fluctuations. Accordingly, we enter into derivative instruments to manage our exposure to commodity price fluctuations, locational differences between a published index and the NYMEX futures on natural gas or crude oil productions, and interest rate fluctuations.

 

Under commodity swap agreements, we exchange a stream of payments over time according to specified terms with another counterparty. Specifically for commodity price swap agreements, we agree to pay an adjustable or floating price tied to an agreed upon index for the commodity, either gas or oil, and in return receive a fixed price based on notional quantities. Under basis swap agreements, we agree to pay an adjustable or floating price tied to two agreed upon indices for gas and in return receive the differential between a floating index and fixed price based on notional quantities.

 

The interest rate swap agreements effectively fix our interest rate on amounts borrowed under the credit facility. The purpose of these instruments is to mitigate our existing exposure to unfavorable interest rate changes. Under interest rate swap agreements, we pay a fixed interest rate payment on a notional amount in exchange for receiving a floating amount based on LIBOR on the same notional amount.

 

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At March 31, 2015, we had the following open commodity derivative contracts:

 

 

 

Index

 

2015

 

2016

 

2017

 

2018

 

Natural gas positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (MMBTUs)

 

NYMEX-HH

 

4,078,287

 

5,433,888

 

5,045,760

 

3,452,172

 

Weighted average price

 

 

 

$

5.73

 

$

4.29

 

$

4.61

 

$

4.05

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps (MMBTUs)

 

 

(1)

3,948,029

 

2,877,047

 

 

 

Weighted average price

 

 

 

$

(0.1663

)

$

(0.1115

)

$

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (BBLs)

 

NYMEX-WTI

 

553,718

 

610,131

 

473,698

 

562,524

 

Weighted average price

 

 

 

$

93.27

 

$

87.27

 

$

84.34

 

$

82.26

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps (BBLs)

 

Argus-

 

288,575

 

 

 

 

Weighted average price

 

Midland-Cushing

 

$

(3.3556

)

$

 

$

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (BBLs)

 

Mont Belvieu

 

173,042

 

 

 

 

Weighted average price

 

 

 

$

34.45

 

$

 

$

 

$

 

 


(1)

Our natural gas basis swaps are traded on the following indices: Centerpoint East, Houston Ship Channel, WAHA and TEXOK.

 

At December 31, 2014, we had the following open commodity derivative contracts:

 

 

 

Index

 

2015

 

2016

 

2017

 

2018

 

Natural gas positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (MMBTUs)

 

NYMEX-HH

 

5,500,236

 

5,433,888

 

5,045,760

 

2,374,800

 

Weighted average price

 

 

 

$

5.72

 

$

4.29

 

$

4.61

 

$

4.28

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps (MMBTUs)

 

 

(1)

5,326,559

 

2,877,047

 

 

 

Weighted average price

 

 

 

$

(0.1661

)

$

(0.1115

)

$

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (BBLs)

 

NYMEX-WTI

 

757,321

 

610,131

 

473,698

 

562,524

 

Weighted average price

 

 

 

$

93.16

 

$

87.27

 

$

84.34

 

$

82.26

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps (BBLs)

 

Argus-

 

397,035

 

 

 

 

Weighted average price

 

Midland-Cushing

 

$

(3.4087

)

$

 

$

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (BBLs)

 

Mont Belvieu

 

236,149

 

 

 

 

Weighted average price

 

 

 

$

34.46

 

$

 

$

 

$

 

 


(1)

Our natural gas basis swaps are traded on the following indices: Centerpoint East, Houston Ship Channel, WAHA and TEXOK.

 

At March 31, 2015, we had the following interest rate swap derivative contracts (in thousands):

 

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Notional

 

 

 

 

 

Effective

 

Maturity

 

Amount

 

Average %

 

Index

 

February 2015

 

February 2017

 

75,000

 

1.72500

%

LIBOR

 

February 2015

 

February 2017

 

75,000

 

1.72750

%

LIBOR

 

June 2012

 

June 2015

 

70,000

 

0.52375

%

LIBOR

 

June 2015

 

June 2017

 

70,000

 

1.42750

%

LIBOR

 

 

At December 31, 2014, we had the following interest rate swap derivative contracts (in thousands):

 

 

 

 

 

Notional

 

 

 

 

 

Effective

 

Maturity

 

Amount

 

Average %

 

Index

 

February 2012

 

February 2015

 

$

150,000

 

0.51750

%

LIBOR

 

February 2015

 

February 2017

 

75,000

 

1.72500

%

LIBOR

 

February 2015

 

February 2017

 

75,000

 

1.72750

%

LIBOR

 

June 2012

 

June 2015

 

70,000

 

0.52375

%

LIBOR

 

June 2015

 

June 2017

 

70,000

 

1.42750

%

LIBOR

 

 

Effect of Derivative Instruments — Balance Sheet

 

The fair value of our commodity and interest rate derivative instruments is included in the tables below (in thousands):

 

 

 

As of March 31, 2015

 

 

 

Current

 

Long-term

 

Current

 

Long-term

 

 

 

Assets

 

Assets

 

Liabilities

 

Liabilities

 

Interest rate

 

 

 

 

 

 

 

 

 

Swaps

 

$

 

$

 

$

2,750

 

$

1,340

 

Gross fair value

 

 

 

2,750

 

1,340

 

Netting arrangements

 

 

 

 

 

Net recorded fair value

 

$

 

$

 

$

2,750

 

$

1,340

 

 

 

 

 

 

 

 

 

 

 

Sale of natural gas production

 

 

 

 

 

 

 

 

 

Price swaps

 

$

13,536

 

$

12,897

 

$

 

$

 

Basis swaps

 

35

 

 

140

 

116

 

Sale of crude oil production

 

 

 

 

 

 

 

 

 

Price swaps

 

27,181

 

33,557

 

 

 

Basis swaps

 

 

 

749

 

 

Sale of NGLs

 

 

 

 

 

 

 

 

 

Price swaps

 

2,639

 

 

 

 

Gross fair value

 

43,391

 

46,454

 

889

 

116

 

Netting arrangements

 

(23

)

 

(23

)

 

Net recorded fair value

 

$

43,368

 

$

46,454

 

$

866

 

$

116

 

 

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As of December 31, 2014

 

 

 

Current

 

Long-term

 

Current

 

Long-term

 

 

 

Assets

 

Assets

 

Liabilities

 

Liabilities

 

Interest rate

 

 

 

 

 

 

 

 

 

Swaps

 

$

 

$

 

$

2,327

 

$

817

 

Gross fair value

 

 

 

2,327

 

817

 

Netting arrangements

 

 

 

 

 

Net recorded fair value

 

$

 

$

 

$

2,327

 

$

817

 

 

 

 

 

 

 

 

 

 

 

Sale of natural gas production

 

 

 

 

 

 

 

 

 

Price swaps

 

$

14,732

 

$

9,170

 

$

 

$

 

Basis swaps

 

1

 

 

286

 

232

 

Sale of crude oil production

 

 

 

 

 

 

 

 

 

Price swaps

 

27,544

 

29,370

 

 

 

Basis swaps

 

 

 

271

 

 

Sale of NGLs

 

 

 

 

 

 

 

 

 

Price swaps

 

3,648

 

 

 

 

Gross fair value

 

45,925

 

38,540

 

557

 

232

 

Netting arrangements

 

(1

)

 

(1

)

 

Net recorded fair value

 

$

45,924

 

$

38,540

 

$

556

 

$

232

 

 

Effect of Derivative Instruments — Statements of Operations

 

The net gain (loss) amounts and classification related to derivative instruments for the periods indicated are as follows (in thousands):

 

 

 

Three Months Ended March 31,

 

 

 

2015

 

2014

 

Commodity derivatives (revenue)

 

$

18,682

 

$

(5,622

)

Interest rate derivatives (other income (expense), net)

 

(1,351

)

(294

)

 

Credit Risk

 

All of our derivative transactions have been carried out in the over-the-counter market. The use of derivative instruments involves the risk that the counterparties may be unable to meet the financial terms of the transactions. We monitor the creditworthiness of each of our counterparties and assess the possibility of whether each counterparty to the derivative contract would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. We also have netting arrangements in place with each counterparty to reduce credit exposure. The derivative transactions are placed with major financial institutions that present minimal credit risks to us. Additionally, we consider ourselves to be of substantial credit quality and have the financial resources and willingness to meet our potential repayment obligations associated with the derivative transactions.

 

9.              Related Parties

 

Ownership in Our General Partner by Lime Rock Management and its Affiliates

 

As of March 31, 2015, Lime Rock Management, an affiliate of Fund I, owned all of the Class A member interests in our general partner, Fund I owned all of the Class B member interests in our general partner and Fund II owned all of the Class C member interests in our general partner. In addition, Fund I owned an aggregate of approximately 30.5% of our outstanding common units, representing their limited partner interest in us. As of March 31, 2015, our general partner owned an approximate 0.1% general partner interest in us, represented by 22,400 general partner units, and all of our incentive distribution rights.

 

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As more fully described in our 2014 Annual Report, we converted 2,240,000 subordinated units on a one-for-one basis into common units pursuant to the terms of our partnership agreement on May 16, 2014. We converted the remaining 4,480,000 subordinated units on a one-for-one basis into common units pursuant to the terms of our partnership agreement on February 13, 2015.

 

Contracts with our General Partner and its Affiliates

 

As more fully described in our 2014 Annual Report, we have entered into agreements with our general partner and its affiliates. For the three months ended March 31, 2015 and 2014, we paid Lime Rock Management approximately $0.4 million and $0.2 million either directly or indirectly related to these agreements, respectively.

 

In connection with the management of our business, Lime Rock Resources Operating Company, Inc. (“ServCo”), an affiliate of our general partner, provides services for invoicing and processing of payments to our vendors. Periodically, ServCo remits cash to us for the net working capital received on our behalf. Changes in the affiliates (payable)/receivable balances during the three months ended March 31, 2015 are included below (in thousands):

 

 

 

 

 

Lime Rock

 

 

 

 

 

ServCo

 

Resources

 

Total

 

 

 

 

 

 

 

 

 

Balance as of December 31, 2014

 

$

5,436

 

$

261

 

$

5,697

 

Expenditures

 

(46,820

)

(263

)

(47,083

)

Cash paid for expenditures

 

50,837

 

 

50,837

 

Revenues and other

 

(3,102

)

2

 

(3,100

)

Balance as of March 31, 2015

 

$

6,351

 

$

 

$

6,351

 

 

Distributions of Available Cash to Our General Partner and Affiliates

 

We will generally make cash distributions to our unitholders and our general partner pro rata. As of March 31, 2015, our general partner and its affiliates held 8,569,600 of our common units and 22,400 general partner units. During the three months ended March 31, 2015 and 2014, we paid cash distributions of $14.0 million and $12.9 million, respectively, to all unitholders as of the respective record dates.

 

We announced our first quarter 2015 distribution on April 20, 2015 as discussed in Note 14.

 

10.       Unitholders’ Equity

 

At-the-Market Offering Program

 

On February 4, 2014, we launched an “at-the-market” offering program (the “ATM Program”) with MLV & Co. LLC (“MLV”) as sales agent. We may sell from time to time through MLV our common units representing limited partner interests having an aggregate offering amount of up to $75.0 million, subject to limitations as described in the Merger Agreement (described in Note 14). Any sales of common units under the ATM Program may be made by any method permitted by law deemed to be an “at-the-market offering” defined by Rule 415 of the Securities Act of 1933, as amended, (the “Securities Act”), including, without limitation, sales made directly on the New York Stock Exchange, or any other existing trading market for our common units or to or through a market maker.

 

Our second lien term loan requires that 50% of the net cash proceeds from any equity offering be used to repay borrowings outstanding under the term loan. During the three months ended March 31, 2015, we did not sell common units under the ATM Program.

 

Units Outstanding

 

As of March 31, 2015, we had 28,074,433 common units and 22,400 general partner units outstanding. As of March 31, 2015, Fund I owned 8,569,600 common units, representing a 30.5% limited partner interest in us.

 

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General Partner Allocation of Loss

 

In accordance with our partnership agreement, the allocation of net loss cannot cause a unitholder to have a deficit balance. Deficit balances are carried by our general partner until net income is generated in a taxable period. Our general partner will recover losses from net income generated prior to the net income being allocated to the remaining unitholders.

 

11.       Net  Income (Loss) Per Limited Partner Unit

 

The following sets forth the calculation of net income (loss) per limited partner unit for the following periods (in thousands, except per unit amounts):

 

 

 

Three Months Ended March 31,

 

 

 

2015

 

2014

 

Net income (loss) available to unitholders

 

$

(24,936

)

$

2,694

 

Less: General partner’s interest in net (income) loss

 

1,839

 

(3

)

Limited partners’ interest in net income (loss)

 

$

(23,097

)

$

2,691

 

 

 

 

 

 

 

Weighted average limited partner units outstanding:

 

 

 

 

 

Common units

 

25,882

 

19,622

 

Subordinated units

 

2,190

 

6,720

 

Total

 

28,072

 

26,342

 

 

 

 

 

 

 

Net income (loss) per limited partner unit (basic and diluted)

 

$

(0.82

)

$

0.10

 

 

Our subordinated units and restricted unit awards are considered to be participating securities for purposes of calculating our net income (loss) per limited partner unit, and accordingly, are included in basic computation as such. Net income (loss) per limited partner unit is determined by dividing the net income (loss) available to the common unitholders, after deducting our general partner’s interest in net income (loss), by the weighted average number of common units and subordinated units outstanding as of March 31, 2015 and 2014. The aggregate number of common units outstanding was 28,074,433, as of March 31, 2015. We did not have any subordinated units outstanding as of March 31, 2015. The aggregate number of common units and subordinated units outstanding was 19,812,246 and 6,720,000, respectively, as of March 31, 2014.

 

12.       Equity-Based Compensation

 

On November 10, 2011, our General Partner adopted a long-term incentive plan (“2011 LTIP”) for employees, consultants and directors of our General Partner and its affiliates, including Lime Rock Management and ServCo, who perform services for us. The 2011 LTIP consists of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, unit awards and other unit-based awards. The 2011 LTIP initially limits the number of units that may be delivered pursuant to vested awards to 1,500,000 common units. As of March 31, 2015, there were 1,025,013 units available for issuance under the 2011 LTIP. The 2011 LTIP is currently administered by our General Partner’s board of directors or a committee thereof.

 

The fair value of restricted units is determined based on the fair market value of the units on the date of grant. The outstanding restricted units vest in equal amounts (subject to rounding) over a three-year period following the date of grant and are entitled to receive quarterly distributions during the vesting period.

 

A summary of the status of the non-vested restricted units as of March 31, 2015 is presented below:

 

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Table of Contents

 

 

 

Number of

 

Weighted Average

 

 

 

Non-vested

 

Grant-date

 

 

 

Restricted Units

 

Fair Value

 

Non-vested restricted units at December 31, 2014

 

361,957

 

$

9.38

 

Granted

 

12,542

 

5.98

 

Vested

 

(11,203

)

18.01

 

Forfeited

 

 

 

Non-vested restricted units at March 31, 2015

 

363,296

 

9.00

 

 

As of March 31, 2015, there was approximately $2.8 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over a weighted average period of approximately 2.3 years. There were 111,691 vested restricted units as of March 31, 2015.

 

13.       Subsidiary Guarantors

 

We and LRE Finance, our 100 percent-owned subsidiary, filed a registration statement on Form S-3 with the SEC on August 28, 2013, and the SEC declared the registration statement effective on September 10, 2013. Securities that may be offered and sold include debt securities that are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act. LRE Finance may co-issue any debt securities issued by us pursuant to the registration statement. LRE Finance was formed solely for the purpose of co-issuing our debt securities and has no material assets or liabilities other than as co-issuer of our debt securities, if and when issued. OLLC, our 100 percent-owned subsidiary, may guarantee any debt securities issued by us and such guarantee will be full and unconditional, subject to customary release provisions. The guarantee will be released (i) automatically upon any sale, exchange or transfer of our equity interests in OLLC, (ii) automatically upon the liquidation and dissolution of OLLC, (iii) following delivery of notice to the trustee under the indenture related to the debt securities of the release of OLLC of its obligations under our revolving credit facility, and (iv) upon legal or covenant defeasance or other satisfaction of the obligations under the related debt securities. Other than LRE Finance, OLLC is our sole subsidiary, and thus, no other subsidiary will guarantee our debt securities.

 

Furthermore, we have no assets or operations independent of OLLC, and there are no significant restrictions upon the ability of OLLC to distribute funds to us by dividend or loan. Finally, none of our or OLLC’s assets represents restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X.

 

14.       Subsequent Events

 

Unit Distribution

 

On April 20, 2015, we announced that the board of directors of our general partner declared a cash distribution for the first quarter of 2015 of $0.1875 per outstanding unit, or $0.75 on an annualized basis. The distribution will be paid on May 15, 2015 to all unitholders of record as of the close of business on May 1, 2015. The aggregate amount of the distribution will be $5.3 million.

 

Merger with Vanguard Natural Resources, LLC

 

On April 20, 2015, we entered into a Purchase Agreement and Plan of Merger (the “Merger Agreement”) with Vanguard Natural Resources, LLC (“Vanguard”), Lighthouse Merger Sub, LLC, a wholly owned indirect subsidiary of Vanguard (“Merger Sub” and together with Vanguard, the “Vanguard Entities”), Lime Rock Management, Fund I, Fund II (together with the Fund I and Lime Rock Management, the “GP Sellers”) and our General Partner (together with the GP Sellers and the Partnership, the “Partnership Entities”). Upon the terms and conditions set forth in the Merger Agreement, Merger Sub will be merged with and into the Partnership, with the Partnership continuing as the surviving entity and as a wholly owned subsidiary of Vanguard (the “Merger”) and, at the same time, all of the limited liability company interests in our General Partner will be acquired by Vanguard. Based upon the recommendation of the conflicts committee of the board of directors of our General Partner (the “Board”), the Board approved the Merger Agreement on April 20, 2015.

 

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At the effective time of the Merger (the “Effective Time”), each of our common units issued and outstanding immediately prior to the Effective Time will be converted into the right to receive 0.550 common units representing limited liability company interests in Vanguard (“Vanguard Units”) or, in the case of fractional Vanguard Units, cash (without interest and rounded up to the nearest whole cent) in an amount equal to the product of (i) such fractional part of a Vanguard Unit multiplied by (ii) the average closing price for a Vanguard Unit as reported on the NASDAQ Global Select Market (the “NASDAQ”) for the ten consecutive full trading days ending at the close of trading on the full trading day immediately preceding the closing date of the transactions contemplated by the Merger Agreement (the “Closing Date”).  Each of our restricted common units that is outstanding pursuant to the 2011 LTIP will vest immediately prior to the Effective Time and be converted into the right to receive Vanguard Units.  In addition, on the Closing Date, Vanguard will issue and deliver to the GP Sellers 12,320 Vanguard Units in exchange for all of the limited liability interests in our General Partner (the “GP Equity Consideration”).

 

As a condition to closing of transactions contemplated under the Merger Agreement, the parties have agreed to execute and deliver a Termination and Continuing Obligations Agreement (the “Termination Agreement”) substantially in the form attached as an exhibit to the Merger Agreement. Pursuant to the Termination Agreement, (i) that certain Omnibus Agreement, entered into, and effective as of, November 16, 2011 (the “Omnibus Agreement”), by and among us, our General Partner, OLLC, Fund I, LRR GP, LLC, the ultimate general partner of each of the Fund I entities, and Lime Rock Management, will be terminated and (ii) the Fund I entities, severally and in proportion to each entity’s Property Contributor Percentage (as defined in the Omnibus Agreement), will agree to indemnify the Partnership, our General Partner, OLLC and all of our and their respective subsidiaries from and against any losses arising out of any federal, state or local income tax liabilities attributable to the ownership or operation of the oil and natural gas properties owned or leased by any of the Partnership, our General Partner, OLLC or our or their respective subsidiaries prior to the closing of our initial public offering. The indemnification obligations of Fund I under the Termination Agreement will survive until the first anniversary of the Closing Date.

 

The Partnership Entities and the Vanguard Entities have each made certain representations and warranties and agreed to certain covenants in the Merger Agreement. Each of the Partnership, our General Partner and Vanguard has agreed, among other things, subject to certain exceptions, to conduct its respective business in the ordinary course during the period between the execution of the Merger Agreement and the Effective Time (unless the Merger Agreement is earlier terminated in accordance with its terms). In addition, we have agreed not to solicit alternative business combination transactions during such period, and, subject to certain exceptions, not to engage in discussions or negotiations regarding any alternative business combination transactions during such period.

 

The closing of the Merger is subject to the satisfaction or waiver of certain customary conditions, including, among others, (i) the approval of the Merger Agreement by our unitholders; (ii) the registration statement on Form S-4 used to register the Vanguard Units to be issued in the Merger being declared effective by the Securities and Exchange Commission (the “SEC”); (iii) the approval for listing on the NASDAQ of the Vanguard Units to be issued in the Merger; (iv) subject to specified materiality standards, the accuracy of the representations and warranties of, and the performance of all covenants by, the parties; (v) the delivery of certain tax opinions; and (vi) entry into the Termination Agreement by the parties thereto.

 

The Merger Agreement contains certain termination rights for each of the Partnership and Vanguard, including, among others, if (i) the Merger is not consummated on or before December 31, 2015; (ii) the requisite approval of the Merger Agreement by our unitholders is not obtained; and (iii) the other party breaches a representation, warranty or covenant, and such breach results in the failure of certain closing conditions to be satisfied (a “terminable breach”). The Merger Agreement also provides that (a) we may terminate the Merger Agreement to enter into a third party’s “superior proposal” and (b) Vanguard may terminate the Merger Agreement if the Board changes its recommendation to our unitholders to approve the Merger Agreement (a “Partnership Change in Recommendation”); provided, in each case, that we pay Vanguard the Termination Fee (as described below).

 

The Merger Agreement provides for the payment of a termination fee of approximately $7.3 million (the “Termination Fee”) by the Partnership to Vanguard upon the termination of the Merger Agreement under specified circumstances, including if: (i) (a) prior to our unitholder meeting, a third party proposal has been publicly submitted, publicly proposed or publicly disclosed and has not been withdrawn at the time of such meeting, (b) thereafter, the Merger Agreement is terminated in accordance with its terms under specified circumstances, and (c) prior to the date that is 12 months after the date of the Merger Agreement is terminated, we enter into or

 

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consummate any definitive agreement related to a third party proposal ; (ii) Vanguard terminates the Merger Agreement due to a Partnership Change in Recommendation; or (iii) we terminate the Merger Agreement to enter into a third party’s “superior proposal.” The Merger Agreement also provides that the non-terminating party may be required to pay the other party’s expenses (up to a maximum of approximately $1.2 million (the “Expenses”) if either party terminates the Merger Agreement due to a terminable breach by the other party. If the Termination Fee is payable at a time when Vanguard has received or concurrently receives payment from us in respect of Expenses, the Termination Fee will be reduced by the amount of such Expenses received by Vanguard.

 

Amendments to the Credit Agreement and Term Loan Agreement

 

On May 4, 2015, we entered into the Fifth Amendment (“Fifth Credit Agreement Amendment”) to our Credit Agreement. The Fifth Credit Agreement Amendment, among other things, (i) increased the interest rate margins applicable to the loans with margins ranging from 2.00% to 3.10% for Eurodollar loans, and from 1.00% to 2.10% for base rate loans, in each case based on utilization of the credit facility, (ii) increased the commitment fee applicable to the unused portion of the borrowing base with amounts ranging from 0.375% to 0.800% based on utilization of the credit facility, (iii) restricted the payments of distributions to $10.6 million through September 30, 2015; however, after October 1, 2015, distributions are subject to having a minimum of 15% availability under a conforming borrowing base amount after the distribution has been paid, and (iv) decreased the borrowing base to $245.0 million. Pursuant to the amendment, the borrowing base will decrease in the amount of $1.0 million per month, beginning in June 2015 and continuing until the next redetermination of the borrowing base in the fall of 2015. The borrowing base of the Credit Agreement will revert to $195.0 million upon the earlier of November 1, 2015 and a termination of the Merger Agreement. If the next scheduled redetermination has not occurred by November 1, 2015, the borrowing base shall decrease to $195.0 million until the scheduled redetermination is completed.

 

On May 4, 2015, we entered into the Fifth Amendment (“Fifth Term Loan Amendment”) to our Term Loan Agreement. The Fifth Term Loan Amendment, among other things, amended the Term Loan Agreement to (i) increase the interest rate margins applicable to the loan with margins for Eurodollar loans and Alternate Base Rate loans increasing to 9.50% and 8.50%, respectfully, after September 30, 2015, and (ii) restrict the payments of distributions to $10.6 million through September 30, 2015; however, after October 1, 2015, distributions are subject to having a minimum of 15% availability under a conforming borrowing base amount.. In connection with the Fifth Term Loan Amendment, we received a waiver on our asset coverage test ratio as discussed in Note 7.

 

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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

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 and natural gas prices;

·                  production volumes;

·                  lease operating expenses;

·                  general and administrative expenses;

·                  future operating results;

·                  cash flows and liquidity;

·                  availability of drilling and production equipment;

·                  general economic conditions;

·                  effectiveness of risk management activities; and

·                  plans, objectives, expectations and intentions.

 

All statements, other than statements of historical fact, are forward-looking statements. These forward-looking statements can be identified by their use of terms and phrases such as “may,” “predict,” “pursue,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “target,” “continue,” “potential,” “should,” “could” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties some of which are beyond our control. Actual results could differ materially from those anticipated in these forward-looking statements. One should consider carefully the risk factors described in Item 1A. “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2014 (“2014 Annual Report”) which describe factors that could cause our actual results to differ from those anticipated in the forward-looking statements, including, but not limited to, the following factors:

 

·                  our ability to generate sufficient cash to pay quarterly distributions on our common units;

·                  our ability to replace the oil and natural gas reserves we produce;

·                  our substantial future capital expenditures, which may reduce our cash available for distribution and could materially affect our ability to make distributions on our common units;

·                  a decline in, or substantial volatility of, oil, natural gas or natural gas liquids (“NGL”) prices;

·                  the risk that oil and natural gas prices remain depressed for a prolonged period of time;

·                  the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production;

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

·                  uncertainty inherent in estimating our reserves;

·                  the risks and uncertainties involved in developing and producing oil and natural gas;

·                  risks related to potential acquisitions, including our ability to make accretive acquisitions on economically acceptable terms or to integrate acquired properties;

·                  competition in the oil and natural gas industry;

·                  cash flows and liquidity;

·                  restrictions and financial covenants contained in the instruments governing our existing indebtedness;

·                  the availability of pipelines, transportation and gathering systems and processing facilities owned by third parties;

·                  electronic, cyber, and physical security breaches;

 

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·                  general economic conditions; and

·                  legislation and governmental regulations, including climate change legislation and federal or state regulation of hydraulic fracturing.

 

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document and speak only as of the date of this report. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

 

Overview

 

LRR Energy, L.P. (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed in April 2011 by Lime Rock Management LP (“Lime Rock Management”), an affiliate of Lime Rock Resources A, L.P. (“LRR A”), Lime Rock Resources B, L.P. (“LRR B”) and Lime Rock Resources C, L.P. (“LRR C”), to operate, acquire, exploit and develop producing oil and natural gas properties in North America with long-lived, predictable production profiles. LRR A, LRR B and LRR C were formed by Lime Rock Management in July 2005 for the purpose of acquiring mature, low-risk producing oil and natural gas properties with long-lived production profiles. As used herein, references to “Fund I” refer collectively to LRR A, LRR B and LRR C; references to “Fund II” refer collectively to Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P.; and references to “Fund III” refer collectively to Lime Rock Resources III-A, L.P. and Lime Rock Resources III-C, L.P. References to “Lime Rock Resources” refer collectively to Fund I, Fund II and Fund III.

 

Our properties are located in the Permian Basin region in West Texas and Southeast New Mexico, the Mid-Continent region in Oklahoma and East Texas and the Gulf Coast region in Texas.

 

Acquisition of Properties

 

On October 1, 2014, we completed an acquisition of oil and natural gas properties in the Stroud field located in Lincoln and Creek Counties, Oklahoma for a purchase price of $38.0 million (the “October 2014 Acquisition”) from an unrelated third party. The October 2014 Acquisition was effective September 1, 2014. We financed the acquisition with borrowings under our Credit Agreement. In January 2015, we paid $0.2 million in cash to the seller related to post-closing adjustments to the purchase price.

 

Results of Operations

 

 

 

Three Months Ended March 31,

 

 

 

2015

 

2014

 

Revenues (in thousands):

 

 

 

 

 

Oil sales

 

$

12,064

 

$

20,156

 

Natural gas sales

 

4,266

 

8,099

 

Natural gas liquids sales

 

1,171

 

3,364

 

Gain (loss) on commodity derivative instruments, net

 

18,682

 

(5,622

)

Other income

 

29

 

31

 

Total revenues

 

36,212

 

26,028

 

 

 

 

 

 

 

Expenses (in thousands):

 

 

 

 

 

Lease operating expense

 

6,772

 

5,835

 

Production and ad valorem taxes

 

1,266

 

2,400

 

Depletion and depreciation

 

8,880

 

8,465

 

Impairment of oil and natural gas properties

 

35,706

 

 

General and administrative expense

 

3,791

 

3,182

 

Interest expense

 

2,769

 

2,541

 

Loss (gain) on interest rate derivative instruments, net

 

1,351

 

294

 

 

 

 

 

 

 

Production:

 

 

 

 

 

Oil (MBbls)

 

275

 

218

 

Natural gas (MMcf)

 

1,518

 

1,622

 

NGLs (MBbls)

 

90

 

85

 

Total (MBoe)

 

618

 

573

 

Average net production (Boe/d)

 

6,867

 

6,367

 

 

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Three Months Ended March 31,

 

 

 

2015

 

2014

 

Average sales price:

 

 

 

 

 

Oil (per Bbl):

 

 

 

 

 

Sales price

 

$

43.87

 

$

92.46

 

Effect of settled commodity derivative instruments

 

31.73

 

(0.79

)

Realized sales price

 

$

75.60

 

$

91.67

 

Natural gas (per Mcf):

 

 

 

 

 

Sales price

 

$

2.81

 

$

4.99

 

Effect of settled commodity derivative instruments

 

2.46

 

0.53

 

Realized sales price

 

$

5.27

 

$

5.52

 

NGLs (per Bbl):

 

 

 

 

 

Sales price

 

$

13.01

 

$

39.58

 

Effect of settled commodity derivative instruments

 

10.51

 

(3.78

)

Realized sales price

 

$

23.52

 

$

35.80

 

 

 

 

 

 

 

Average unit cost per Boe:

 

 

 

 

 

Lease operating expenses

 

$

10.96

 

$

10.18

 

Production and ad valorem taxes

 

2.05

 

4.19

 

Depletion and depreciation

 

14.37

 

14.76

 

General and administrative expenses

 

6.13

 

5.55

 

 

Our Results for the Three Months Ended March 31, 2015 Compared to the Three Months Ended March 31, 2014

 

We recorded net loss of $24.9 million for the three months ended March 31, 2015 compared to net income of $2.7 million for the three months ended March 31, 2014, primarily related the impairment charge of $35.7 million recorded in the three months ended March 31, 2015. The following discussion summarizes key components of the changes between periods.

 

Sales Revenues.  A summary of increases (decreases) in our oil, natural gas and NGL revenues between the three months ended March 31, 2014 and March 31, 2015 follows (in thousands):

 

Oil, natural gas and NGL revenues-prior period

 

$

31,619

 

Increase (decrease)

 

 

 

Price realization

 

 

 

Oil

 

(10,593

)

Natural gas

 

(3,541

)

NGLs

 

(2,258

)

Sales volumes

 

 

 

Oil

 

2,501

 

Natural gas

 

(292

)

NGLs

 

65

 

Oil, natural gas and NGL revenues-current period

 

$

17,501

 

 

Sales revenues decreased from $31.6 million for the three months ended March 31, 2014 to $17.5 million for the three months ended March 31, 2015, primarily due to lower commodity price realizations offset by higher oil and NGL sales volumes. Sales revenues for the three months ended March 31, 2015 consisted of oil sales of $12.0 million, natural gas sales of $4.3 million and NGL sales of $1.2 million. Sales revenues for the three months ended March 31, 2014 consisted of oil sales of $20.1 million, natural gas sales of $8.1 million and NGL sales of $3.4 million.

 

Our production volumes for the three months ended March 31, 2015 included 365 MBbls of oil and NGLs and 1,518 MMcf of natural gas, or 4,056 Bbl/d of oil and NGLs and 16,867 Mcf/d of natural gas. On an equivalent basis, production for the period was 618 MBoe, or 6,867 Boe/d. Our average net production for the three months ended March 31, 2015 was negatively impacted by flaring at the Red Lake field of approximately 50 Boe/d.  Our production volumes for the three months ended March 31, 2014 included 303 MBbls of oil and NGLs and 1,622 MMcf of natural gas, or 3,367 Bbl/d of oil and NGLs and 18,022 Mcf/d of natural gas. On an equivalent basis, production for the period was 573 MBoe, or 6,367 Boe/d. Our average net production for the three months ended March 31, 2014 was negatively impacted by flaring at the Red Lake field of approximately 75 Boe/d and the winter storms and other delays of approximately 100 Boe/d.

 

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Our average sales price per Bbl for oil and NGLs for the three months ended March 31, 2015, excluding the effect of commodity derivative contracts, was $43.87 and $13.01, respectively. Our average sales price per Mcf of natural gas for the three months ended March 31, 2015, excluding the effect of commodity derivative contracts, was $2.81. Our average sales price per Bbl for oil and NGLs for the three months ended March 31, 2014, excluding the effect of commodity derivative contracts, was $92.46 and $39.58, respectively. Our average sales price per Mcf of natural gas for the three months ended March 31, 2014, excluding the effect of commodity derivative contracts, was $4.99.

 

Effects of Commodity Derivative Contracts.  Due to changes in oil and natural gas prices, we recorded a net gain from our commodity hedging program for the three months ended March 31, 2015 of approximately $18.7 million, which is comprised of positive net cash settlements and amortization of purchases of approximately $13.4 million and increases in the fair value of derivatives of approximately $5.3 million. For the three months ended March 31, 2014, we recorded a net loss from our commodity hedging program of approximately $5.6 million, which is comprised of positive net cash settlements and amortization of approximately $0.4 million and declines in fair value of derivatives of approximately $6.0 million. Lower commodity prices during the quarter lead to the significant impact on our gain on commodity derivative contracts for the quarter ended March 31, 2015.

 

Lease Operating Expense.  Our lease operating expenses were approximately $6.8 million, or $10.96 per Boe, for the three months ended March 31, 2015 compared to approximately $5.8 million, or $10.18 per Boe, for the three months ended March 31, 2014. The primary driver of the increased lease operating expenses was as a result of the acquisition of oil and natural gas properties in the Stroud field in the fourth quarter of 2014.

 

Production and Ad Valorem Taxes.  Our production and ad valorem taxes were approximately $1.3 million, or $2.05 per Boe, for the three months ended March 31, 2015 compared to approximately $2.4 million, or $4.19 per Boe, for the three months ended March 31, 2014. Production taxes accounted for approximately $1.2 million and ad valorem taxes for $0.1 million of the total taxes recorded during the three months ended March 31, 2015. Production taxes accounted for approximately $2.3 million and ad valorem taxes for $0.1 million of the total taxes recorded during the three months ended March 31, 2014. Production taxes for the three months ended March 31, 2015 declined from the same period in 2014 primarily due to lower commodity price realizations and the lower net taxable value associated with the production taxes.

 

Depletion and Depreciation.  Our depletion and depreciation expense was $8.9 million, or $14.37 per Boe, for the three months ended March 31, 2015 compared to $8.5 million, or $14.76 per Boe, for the three months ended March 31, 2014.

 

Impairment of Oil and Natural Gas Properties.  For the three months ended March 31, 2015, we recorded a total non-cash impairment charge of $35.7 million to impair the value of our proved oil and natural gas properties in the Permian Basin, Gulf Coast, and the Mid-Continent regions. We did not record an impairment charge in the three months ended March 31, 2014. If future oil or natural gas prices or reserves decline further, the estimated undiscounted future cash flows for our oil and natural gas properties may not exceed the net capitalized costs for such properties and a non-cash impairment charge may be required to be recognized in future periods. As of May 1, 2015, the NYMEX-WTI oil spot price was $59.15 per Bbl and the NYMEX-Henry Hub natural gas spot price was $2.67 per MMBtu.

 

General and Administrative Expenses.  Our general and administrative expenses were approximately $3.8 million, or $6.13 per Boe, for the three months ended March 31, 2015 compared to approximately $3.2 million, or $5.55 per Boe, for the three months ended March 31, 2014. The increase in general and administrative expense is primarily related to expenses associated with evaluating strategic alternatives and consulting fees.

 

Interest Expense.  Our interest expense is comprised of interest on our credit facility and term loan and amortization of debt issuance costs. Interest expense was approximately $2.8 million and $2.5 million for the three months ended March 31, 2015 and 2014, respectively.

 

Effects of Interest Rate Derivatives. Loss on interest rate derivative contracts, net, was approximately $1.4 million for the three months ended March 31, 2015, including $0.4 million in negative cash settlements and $1.0

 

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million in declines in fair value of the derivatives. Loss on interest rate derivative contracts, net, was approximately $0.3 million for the three months ended March 31, 2014, including $0.2 million in negative cash settlements and $0.1 million in declines in fair value of the derivatives.

 

Non-GAAP Financial Measures

 

Below we disclose the non-GAAP financial measures Adjusted EBITDA and Distributable Cash Flow for the periods presented and provide reconciliations of these items to net income (loss), our most directly comparable financial performance measure calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income (loss) plus or minus:

 

·                  Income tax expense;

·                  Interest expense-net, including loss (gain) on interest rate derivative instruments, net;

·                  Depletion and depreciation;

·                  Accretion of asset retirement obligations;

·                  Amortization of equity awards;

·                  Loss (gain) on settlement of asset retirement obligations;

·                  Loss (gain) on commodity derivative instruments, net;

·                  Commodity derivative instrument net cash settlements;

·                  Impairment of oil and natural gas properties; and

·                  Other non-recurring 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, commercial banks, research analysts and others, to assess our financial performance as compared to that of other companies and partnerships in our industry, without regard to financing methods, capital structure or historical cost basis.

 

We define Distributable Cash Flow as Adjusted EBITDA less cash income tax expense, cash interest expense and estimated maintenance capital expenditures.

 

Distributable Cash Flow is a supplemental financial measure used by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by us (prior to the establishment of any retained cash reserve by our general partner) to the cash distributions we expect to pay our unitholders. Distributable Cash Flow is also an important financial measure for our unitholders as it serves as an indicator of our success in providing a cash return on investment. Specifically, Distributable Cash Flow indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable Cash Flow is a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the yield is based on the amount of cash distributions the entity pays to a unitholder compared to the unit price.

 

Our management believes that both Adjusted EBITDA and Distributable Cash Flow are useful to investors because these measures are used by many partnerships in the industry as measures of operating and financial performance and are commonly employed by financial analysts and others to evaluate the operating and financial performance from period to period and to compare it with the performance of other publicly traded partnerships within the industry. Adjusted EBITDA and Distributable Cash Flow should not be considered alternatives to net income (loss), operating income (loss), or any other measures of financial performance presented in accordance with GAAP. Our Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA and Distributable Cash Flow in the same manner.

 

Our Adjusted EBITDA for the three months ended March 31, 2015 and 2014 was approximately $19.6 million and $21.0 million, respectively. The decrease was primarily driven by lower revenues due to the decline in commodity prices and higher operating expenses.

 

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Our Distributable Cash Flow for the three months ended March 31, 2015 and 2014 was approximately $11.8 million and $13.4 million, respectively. The decrease in Distributable Cash Flow was driven by the decreased Adjusted EBITDA as discussed above.

 

Reconciliation of Adjusted EBITDA and Distributable Cash Flow to Net Income

 

The following table presents a reconciliation of Adjusted EBITDA and Distributable Cash Flow to net income, our most directly comparable GAAP financial performance measure, for each of the periods indicated.

 

 

 

Three Months Ended March 31,

 

(in thousands)

 

2015

 

2014

 

 

 

 

 

 

 

Net income (loss)

 

$

(24,936

)

$

2,694

 

Income tax expense

 

38

 

74

 

Interest expense-net, including loss (gain) on interest rate derivative instruments, net

 

4,120

 

2,835

 

Depletion and depreciation

 

8,880

 

8,465

 

Accretion of asset retirement obligations

 

511

 

503

 

Amortization of equity awards

 

345

 

285

 

Loss (gain) on settlement of asset retirement obligations

 

64

 

40

 

Loss (gain) on commodity derivative instruments, net

 

(18,682

)

5,622

 

Commodity derivative instrument net cash settlements

 

13,519

 

523

 

Impairment of oil and natural gas properties

 

35,706

 

 

Adjusted EBITDA

 

$

19,565

 

$

21,041

 

 

 

 

Three Months Ended March 31,

 

 

 

2015

 

2014

 

Adjusted EBITDA

 

19,565

 

21,041

 

Cash income tax expense

 

(38

)

(44

)

Cash interest expense

 

(2,943

)

(2,644

)

Estimated maintenance capital (1)

 

(4,750

)

(5,000

)

Distributable Cash Flow

 

$

11,834

 

$

13,353

 

 


(1)         Estimated maintenance capital expenditures as defined by our partnership agreement represents our estimate of the amount of capital required on average per year to maintain our production over the long term.

 

Liquidity and Capital Resources

 

On April 20, 2015, we and Vanguard Natural Resources, LLC (“Vanguard”) announced the signing of a Purchase Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which a subsidiary of Vanguard will merge into LRR Energy, and at the same time, Vanguard will acquire LRE GP, LLC, our general partner for total consideration of $251.0 million in Vanguard common units and the assumption of our net debt of $288.0 million. As a result of the transaction, we and our general partner will become wholly owned subsidiaries of Vanguard.  The transaction, which has been approved by the boards of directors of both companies, including the Conflicts Committee of our Board of Directors, will be a tax-free unit-for-unit transaction with an exchange ratio of 0.550 Vanguard common units for each of our common units issued an outstanding immediately prior to the effective time of the merger.  In addition, Vanguard will acquire all of the limited liability company interests in LRE GP, LLC in exchange for 12,320 Vanguard common units.

 

Our ability to finance our operations, including funding capital expenditures, to meet our indebtedness obligations, to refinance our indebtedness, to meet our collateral requirements, or to pay our distributions depends on our ability to generate cash. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including commodity prices, particularly for oil and natural gas, weather and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. Our primary sources of liquidity and capital resources are cash

 

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flows generated by operating activities.

 

In February 2014, we launched the ATM Program with MLV & Co. LLC (“MLV”) as sales agent. We may sell from time to time through MLV our common units representing limited partner interests having an aggregate offering amount of up to $75.0 million, subject to limitations as described in the Merger Agreement. Our second lien term loan requires that 50% of the net cash proceeds from any equity offering be used to repay borrowings outstanding under the term loan. Any sales of common units under the ATM Program may be made by any method permitted by law deemed to be an “at-the-market offering” defined by Rule 415 of the Securities Act, including, without limitation, sales made directly on the New York Stock Exchange, on any other existing trading market for our common units or to or through a market maker. During the three months ended March 31, 2015, we did not sell common units under the ATM Program.

 

We enter into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy, we enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved developed producing reserves over a three-to-five year period at a given point in time, although we may from time to time hedge more or less than this approximate range.

 

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders and our general partner. In making cash distributions, our general partner attempts to avoid large variations in the amount we distribute from quarter to quarter. In order to facilitate this, our partnership agreement permits our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions.

 

Based on the number of common units and general partner units outstanding as of May 1, 2015, quarterly distributions to all of our unitholders at our current quarterly distribution rate would total $5.3 million. The Merger Agreement prohibits an increase in the distribution from the current quarterly rate.

 

We may borrow to make distributions to our unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to sustain our level of distributions. In addition, a significant portion of our production is hedged. We are generally required to settle our commodity hedge derivatives within five days of the end of the month. As is typical in the oil and gas industry, we generally do not receive the proceeds from the sale of our hedged production until 45 to 60 days following the end of the month. As a result, when commodity prices increase above the fixed price in the derivative contracts, we are required to pay the derivative counterparty the difference between the fixed price in the derivative contract and the market price before we receive the proceeds from the sale of the hedged production. If this occurs, we may make working capital borrowings to fund our distributions. Because we distribute all of our available cash, we will not have those amounts available to reinvest in our business to increase our proved reserves and production and as a result, we may not grow as quickly as other oil and gas entities or at all.

 

We are committed to reinvesting a sufficient amount of our cash flow to fund our exploitation and development capital expenditures in order to maintain our production. If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures or further reduce distributions to unitholders.

 

Based upon current oil and natural gas price expectations and our commodity derivatives positions at March 31, 2015, which cover 85% of our estimated production from total proved developed producing reserves, we anticipate that our cash on hand and cash flow from operations will provide us sufficient working capital to fund our total planned 2015 capital expenditures and cash distributions.

 

We expect to spend $19.0 million in total capital expenditures in 2015. Our 2015 budget consists entirely of maintenance capital expenditures. We may further reduce our capital expenditure budget as we continue to monitor commodity prices and liquidity.

 

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Credit Agreement

 

We, as guarantor, and our wholly owned subsidiary, OLLC, as borrower, are parties to a five-year, $750 million senior secured revolving credit facility, as amended (the “Credit Agreement”), that matures on October 1, 2019. The Intercreditor Agreement (as described below under Term Loan Agreement) limits the amount of indebtedness outstanding at any time under the Credit Agreement (including undrawn amounts under letters of credit) to an amount not to exceed $500.0 million in the aggregate. The Credit Agreement is reserve-based and we are permitted to borrow under our credit facility an amount up to the borrowing base, which was $260 million as of March 31, 2015. Our borrowing base, which is primarily based on the estimated value of our oil, NGL and natural gas properties and our commodity derivative contracts, is subject to redetermination semi-annually by our lenders and once during the interim periods at their sole discretion.

 

In the second quarter of 2015, primarily as a result of significantly lower commodity prices, our borrowing base was reduced to $245.0 million under an amendment to our Credit Agreement. Pursuant to the amendment, the borrowing base will decrease by $1.0 million per month beginning in June 2015 and continuing until the next borrowing base redetermination in November 2015. The amendment is discussed in Note 14.

 

If we fail to perform our obligations under the covenants described in our 2014 Annual Report, the revolving credit commitments could be terminated and any outstanding indebtedness under the Credit Agreement, together with accrued interest, could be declared immediately due and payable. As of March 31, 2015, we were in compliance with our covenants contained in the Credit Agreement.

 

At March 31, 2015, we had $240.0 million of outstanding borrowings under our Credit Agreement and available borrowing capacity of $20.0 million. As of May 4, 2015, we had approximately $240.0 million of outstanding borrowings under our Credit Agreement and available borrowing capacity of approximately $5.0 million.

 

Term Loan Agreement

 

We, as parent guarantor, and our wholly owned subsidiary, OLLC, as borrower, are parties to a Second Lien Credit Agreement (the “Term Loan Agreement”). The Term Loan Agreement provides for a $50 million senior secured second lien term loan to OLLC. OLLC borrowed $50 million under the Term Loan Agreement and used the borrowings to repay outstanding borrowings under the Credit Agreement.

 

The Term Loan Agreement contains various covenants and restrictive provisions as described in our 2014 Annual Report. As of March 31, 2015, we were in compliance with the leverage and current ratios contained in our Term Loan Agreement. We are required to test the asset coverage ratio at specified intervals as described in the Term Loan Agreement, including during the redetermination of our borrowing base under our Credit Agreement. We were not in compliance with the asset coverage ratio during the borrowing base redetermination in the second quarter of 2015; however, we received a waiver from our lender in the Term Loan Agreement for the asset coverage ratio covenant. We entered into an amendment to our Term Loan Agreement as discussed in Note 14.

 

At March 31, 2015, we had $50.0 million of outstanding borrowings under our Term Loan Agreement and no available borrowing capacity.

 

Commodity Derivative Contracts

 

The following table summarizes, for the periods presented, the weighted average price and notional volumes of our oil, NGL and natural gas swaps in place as of March 31, 2015. The weighted average price is based on the swap price for oil, NGL and natural gas swaps. We use swaps as a mechanism for managing commodity price risks whereby we pay the counterparty floating prices and receive fixed prices from the counterparty. By entering into the hedge agreements, we mitigate the effect on our cash flows of changes in the prices we receive for our oil, NGL and natural gas production.

 

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Oil

 

NGL

 

Natural Gas

 

 

 

(NYMEX-WTI)

 

(Mount Belvieu)

 

(NYMEX-Henry Hub)

 

 

 

Weighted Average

 

Weighted Average

 

Weighted Average

 

Term

 

$/Bbl

 

Bbls/d

 

$/Bbl

 

Bbls/d

 

$/MMbtu

 

MMbtu/d

 

2015

 

$

93.27

 

2,014

 

$

34.45

 

629

 

$

5.73

 

14,830

 

2016

 

$

87.27

 

1,672

 

$

 

 

$

4.29

 

14,887

 

2017

 

$

84.34

 

1,298

 

$

 

 

$

4.61

 

13,824

 

2018

 

$

82.26

 

1,541

 

$

 

 

$

4.05

 

9,458

 

 

The following table summarizes, for the periods presented, our natural gas basis swaps in place as of March 31, 2015. These contracts are designed to effectively fix a price differential between the NYMEX-Henry Hub price and the index price at which the physical natural gas is sold.

 

 

 

Centerpoint East

 

Houston Ship Channel

 

WAHA

 

TEXOK

 

Term

 

$/MMbtu

 

MMbtu/d

 

$/MMbtu

 

MMbtu/d

 

$/MMbtu

 

MMbtu/d

 

$/MMbtu

 

MMbtu/d

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

$

(0.2293

)

5,851

 

$

(0.0963

)

2,968

 

$

(0.1381

)

4,703

 

$

(0.1338

)

834

 

2016

 

$

 

 

$

(0.0810

)

2,691

 

$

(0.1326

)

4,408

 

$

(0.0975

)

784

 

 

The following table summarizes, for the period presented, our oil basis swaps in place as of March 31, 2015. These contracts are designed to effectively fix a price differential between the NYMEX-WTI price and the index price at which the physical oil is sold.

 

 

 

Midland-Cushing

 

Term

 

$/Bbl

 

Bbl/d

 

 

 

 

 

 

 

2015

 

$

(3.3556

)

1,049

 

 

Cash Flows

 

Cash flows provided by (used in) operating, investing and financing activities were as follows for the periods indicated (in thousands):

 

 

 

Three Months Ended March 31,

 

 

 

2015

 

2014

 

 

 

 

 

 

 

Net cash provided by (used in):

 

 

 

 

 

Operating activities

 

$

15,648

 

$

16,126

 

Investing activities

 

(12,509

)

(6,738

)

Financing activities

 

(3,975

)

(8,647

)

 

Operating Activities.

 

Net cash provided by operating activities was $15.6 million and $16.1 million for the three months ended March 31, 2015 and 2014, respectively. Revenues fluctuate due to the volatility of commodity prices, and therefore our cash provided by operating activities is impacted by the prices received for oil and natural gas sales, as well as levels of production volumes and operating expenses.

 

Our working capital totaled $51.5 million and $49.5 million at March 31, 2015 and December 31, 2014, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $2.7 million and $3.6 million at March 31, 2015 and December 31, 2014, respectively.

 

Investing Activities.

 

Net cash used in investing activities was $12.5 million for the three months ended March 31, 2015, which

 

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primarily represented $12.3 million of additions to our property and equipment balances and $0.2 million related to post closing adjustments for the October 2014 acquisition of oil and gas natural properties. Net cash used in investing activities was $6.7 million for the three months ended March 31, 2014, which primarily represented additions to our property and equipment balances during the periods.

 

Financing Activities.

 

Cash flows used in financing activities was $4.0 million for the three months ended March 31, 2015, and consisted of borrowings under our revolving credit facility of approximately $10.0 million offset by distributions to unitholders of $14.0 million.

 

Cash flows used in financing activities was $8.6 million for the three months ended March 31, 2014, and consisted of net proceeds received from an equity offering of approximately $4.3 million offset by distributions to unitholders of $12.9 million.

 

Off-Balance Sheet Arrangements

 

As of March 31, 2015, we had no off-balance sheet arrangements.

 

Critical Accounting Policies and Estimates

 

There have been no material changes to our critical accounting policies from those described in our 2014 Annual Report.

 

Recently Issued Accounting Pronouncements

 

Refer to Note 2 of the consolidated condensed financial statements.

 

Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

 

There have been no material changes to the commodity price risk, interest rate risk and counterparty and customer credit risk discussed in our 2014 Annual Report under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure About Market Risk.”

 

Item 4.  Controls and Procedures.

 

Evaluation of Disclosure Controls and Procedures

 

As required by Rule 13a-15(b) of the Securities Exchange Act, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officers and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this 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 or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officers and principal financial officer, 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. Our principal executive officers and principal financial officer, with the participation of management, have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2015.

 

Changes in Internal Control over Financial Reporting

 

There were no changes in our internal control over financial reporting during the quarter ended March 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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Table of Contents

 

PART II—OTHER INFORMATION

 

Item 1.  Legal Proceedings.

 

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, neither we nor our general partner is currently a party to any material legal proceedings. In addition, we are not aware of any significant legal or governmental proceedings against us or our general partner, or contemplated to be brought against us or our general partner, under the various environmental protection statues to which we or our general partner is subject.

 

Item 1A.  Risk Factors.

 

Failure to complete the merger with Vanguard Natural Resources, LLC (“Vanguard”) or delays in completing the merger could negatively affect our unit price and future businesses and operations.

 

There is no assurance that we will be able to consummate the merger. If the merger is not completed for any reason, we may be subject to a number of risks, including the following:

 

·                  we will not realize the benefits expected from the merger, including a potentially enhanced financial and competitive position;

·                the current market price of our common units may reflect a market assumption that the merger will occur and a failure to complete the merger could result in a negative perception of us by the stock market and cause a decline in the market price of our common units

·                certain costs relating to the merger, including certain investment banking and legal fees and expenses, must be paid even if the merger is not completed, and we may be required to pay substantial fees to Vanguard if the merger agreement is terminated under specified circumstances;

·                our borrowing base will be decreased to $195.0 million, an amount below our current outstanding borrowings; and

·                we would continue to face the risks that we currently face as an independent company.

 

Delays in completing the merger could exacerbate uncertainties concerning the effect of the merger, which may have an adverse effect on our business following the merger and could defer or detract from the realization of the benefits expected to result from the merger.

 

There may be substantial disruption to our business and distraction of our management and employees as a result of the merger.

 

There may be substantial disruption to our business and distraction of our management and employees from day-to-day operations because matters related to the merger may require substantial commitments of time and resources, which could otherwise have been devoted to other opportunities that could have been beneficial to us.

 

We are subject to provisions under the merger agreement that limit our ability to pursue alternatives to the merger, that could discourage a potential competing acquirer from making a favorable alternative transaction proposal to us and, in specified circumstances under the merger agreement, that could require us to reimburse Vanguard for up to approximately $1.2 million of its out-of-pocket expenses and pay Vanguard a termination fee of approximately $7.3 million.

 

Under the merger agreement, we are restricted from entering into alternative transactions.  Unless and until the merger agreement is terminated, subject to specified exceptions, we are restricted from initiating, soliciting, knowingly encouraging or knowingly facilitating any inquiry, proposal or offer for a competing acquisition proposal with any person.  Under the merger agreement, in the event of a potential change by the board of directors of our general partner of its recommendation with respect to the proposed merger in light of a superior proposal, we must provide Vanguard notice to allow Vanguard to propose an adjustment to the terms and conditions of the merger agreement. These provisions could discourage a third party that may have an

 

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interest in acquiring all or a significant part of us from considering or proposing that acquisition, even if such third party were prepared to pay consideration with a higher per unit market value than the merger consideration, or might result in a potential competing acquirer of us proposing to pay a lower price than it would otherwise have proposed to pay because of the added expense of the termination fee that may become payable in specified circumstances.

 

The merger agreement requires us to pay a termination fee of approximately $7.3 million to Vanguard upon the termination of the merger agreement under specified circumstances, including if: (i) (a) prior to our unitholder meeting, a third party proposal has been publicly submitted, publicly proposed or publicly disclosed and has not been withdrawn at the time of such meeting, (b) thereafter, the merger agreement is terminated in accordance with its terms under specified circumstances, and (c) prior to the date that is 12 months after the date of the merger agreement is terminated, we enter into or consummate any definitive agreement related to a third party proposal; (ii) Vanguard terminates the merger agreement as a result of the board of directors of our general partner changing its recommendation regarding the merger; or (iii) we terminate the merger agreement to enter into a third party’s “superior proposal.”  Under the merger agreement, we may also be required to pay Vanguard expenses (up to a maximum of approximately $1.2 million) in certain circumstances.  If we are required to pay the termination fee under the merger agreement, it could have a material adverse effect on our business, financial condition and results of operations.

 

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds.

 

None.

 

Item 3.  Defaults Upon Senior Securities.

 

None.

 

Item 4.  Mine Safety Disclosures.

 

Not applicable.

 

Item 5.  Other Information.

 

None.

 

Item 6.  Exhibits.

 

Exhibit Number

 

Description

 

 

 

3.1

 

Certificate of Limited Partnership of LRR Energy, L.P. dated as of April 28, 2011 (incorporated by reference to Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-174017), filed on May 6, 2011).

 

 

 

3.2

 

First Amended and Restated Agreement of Limited Partnership of LRR Energy, L.P. dated as of November 16, 2011 (incorporated by reference to Exhibit 3.2 to the Partnership’s Annual Report on Form 10-K (SEC File No. 001-35344), filed on March 27, 2012).

 

 

 

3.3

 

Certificate of Formation of LRE GP, LLC dated as of April 28, 2011 (incorporated by reference to Exhibit 3.4 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-174017), filed on May 6, 2011).

 

 

 

3.4

 

Amended and Restated Limited Liability Company Agreement of LRE GP, LLC dated as of November 16, 2011 (incorporated by reference to Exhibit 3.2 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on November 22, 2011).

 

 

 

31.1*

 

Certification by Co-Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) under the

 

30



Table of Contents

 

 

 

Securities Exchange Act of 1934.

 

 

 

31.2*

 

Certification by Co-Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934.

 

 

 

31.3*

 

Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934.

 

 

 

32.1*

 

Certification by Co-Chief Executive Officers 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.INS**

 

XBRL Instance Document.

 

 

 

101.SCH**

 

XBRL Taxonomy Extension Schema Document.

 

 

 

101.CAL**

 

XBRL Taxonomy Extension Calculation Linkbase Document.

 

 

 

101.DEF**

 

XBRL Taxonomy Extension Definition Linkbase Document.

 

 

 

101.LAB**

 

XBRL Taxonomy Extension Label Linkbase Document.

 

 

 

101.PRE**

 

XBRL Taxonomy Extension Presentation Linkbase Document.

 


*   Filed herewith

** Submitted electronically herewith

 

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Table of Contents

 

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.

 

 

LRR Energy, L.P.

 

 

 

 

By:

LRE GP, LLC,

 

 

its General Partner

 

 

 

Date: May 6, 2015

By:

/s/ Eric Mullins

 

 

Eric Mullins

 

 

Co-Chief Executive Officer

 

 

 

 

 

 

Date: May 6, 2015

By:

/s/ Jaime R. Casas

 

 

Jaime R. Casas

 

 

Vice President and Chief Financial Officer

 

 

(Principal Financial Officer)

 

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Table of Contents

 

EXHIBIT INDEX

 

Exhibit Number

 

Description

 

 

 

3.1

 

Certificate of Limited Partnership of LRR Energy, L.P. dated as of April 28, 2011 (incorporated by reference to Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-174017), filed on May 6, 2011).

 

 

 

3.2

 

First Amended and Restated Agreement of Limited Partnership of LRR Energy, L.P. dated as of November 16, 2011 (incorporated by reference to Exhibit 3.2 to the Partnership’s Annual Report on Form 10-K (SEC File No. 001-35344), filed on March 27, 2012).

 

 

 

3.3

 

Certificate of Formation of LRE GP, LLC dated as of April 28, 2011 (incorporated by reference to Exhibit 3.4 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-174017), filed on May 6, 2011).

 

 

 

3.4

 

Amended and Restated Limited Liability Company Agreement of LRE GP, LLC dated as of November 16, 2011 (incorporated by reference to Exhibit 3.2 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on November 22, 2011).

 

 

 

31.1*

 

Certification by Co-Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934.

 

 

 

31.2*

 

Certification by Co-Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934.

 

 

 

31.3*

 

Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934.

 

 

 

32.1*

 

Certification by Co-Chief Executive Officers 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.INS**

 

XBRL Instance Document.

 

 

 

101.SCH**

 

XBRL Taxonomy Extension Schema Document.

 

 

 

101.CAL**

 

XBRL Taxonomy Extension Calculation Linkbase Document.

 

 

 

101.DEF**

 

XBRL Taxonomy Extension Definition Linkbase Document.

 

 

 

101.LAB**

 

XBRL Taxonomy Extension Label Linkbase Document.

 

 

 

101.PRE**

 

XBRL Taxonomy Extension Presentation Linkbase Document.

 


*   Filed herewith

** Submitted electronically herewith

 

33