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 June 30, 2014

 

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

 

(I.R.S. Employer

incorporation or organization)

 

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 22,969,599 Common Units, 4,480,000 Subordinated Units and 22,400 General Partner Units outstanding as of July 31, 2014.  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 June 30, 2014 and December 31, 2013

 

1

 

Unaudited Consolidated Condensed Statements of Operations for the Three and Six Months Ended June 30, 2014 and 2013

 

2

 

Unaudited Consolidated Condensed Statement of Changes in Unitholders’ Equity as of June 30, 2014

 

3

 

Unaudited Consolidated Condensed Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013

 

4

 

Notes to Unaudited Consolidated Condensed Financial Statements

 

5

Item 2.

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

 

16

Item 3.

Quantitative and Qualitative Disclosures About Market Risk.

 

27

Item 4.

Controls and Procedures.

 

27

 

 

 

 

 

PART II — OTHER INFORMATION

 

 

 

 

 

 

Item 1.

Legal Proceedings.

 

28

Item 1A.

Risk Factors.

 

28

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds.

 

28

Item 3.

Defaults Upon Senior Securities.

 

28

Item 4.

Mine Safety Disclosures.

 

28

Item 5.

Other Information.

 

28

Item 6.

Exhibits.

 

28

 

Signatures.

 

30

 

i



Table of Contents

 

PART I—FINANCIAL INFORMATION

 

Item 1. Financial Statements.

 

LRR Energy, L.P.

Consolidated Condensed Balance Sheets

(Unaudited)

(in thousands, except unit amounts)

 

 

 

June 30, 2014

 

December 31, 2013

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

2,871

 

$

4,417

 

Accounts receivable

 

9,792

 

9,867

 

Commodity derivative instruments

 

8,022

 

9,726

 

Due from affiliates

 

5,737

 

 

Prepaid expenses

 

1,717

 

1,603

 

Total current assets

 

28,139

 

25,613

 

Property and equipment (successful efforts method)

 

895,352

 

876,674

 

Accumulated depletion, depreciation and impairment

 

(449,054

)

(431,837

)

Total property and equipment, net

 

446,298

 

444,837

 

Commodity derivative instruments

 

5,569

 

16,746

 

Deferred financing costs, net of accumulated amortization and other

 

1,039

 

1,154

 

TOTAL ASSETS

 

$

481,045

 

$

488,350

 

LIABILITIES AND UNITHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accrued liabilities

 

$

4,797

 

$

2,300

 

Accrued capital cost

 

4,115

 

2,574

 

Due to affiliates

 

 

255

 

Commodity derivative instruments

 

5,783

 

2,217

 

Interest rate derivative instruments

 

1,304

 

648

 

Asset retirement obligations

 

503

 

488

 

Total current liabilities

 

16,502

 

8,482

 

Long-term liabilities:

 

 

 

 

 

Commodity derivative instruments

 

3,643

 

174

 

Interest rate derivative instruments

 

1,915

 

1,554

 

Term loan

 

50,000

 

50,000

 

Revolving credit facility

 

195,000

 

200,000

 

Asset retirement obligations

 

36,933

 

35,838

 

Deferred tax liabilities

 

83

 

44

 

Total long-term liabilities

 

287,574

 

287,610

 

Total liabilities

 

304,076

 

296,092

 

Unitholders’ equity:

 

 

 

 

 

General partner (22,400 units issued and outstanding as of June 30, 2014 and December 31, 2013)

 

277

 

303

 

Public common unitholders (18,584,790 units issued and outstanding as of June 30, 2014 and 17,710,334 units issued and outstanding as of December 31, 2013)

 

175,920

 

181,290

 

Affiliated common unitholders (4,089,600 units issued and outstanding as of June 30, 2014 and 1,849,600 issued and outstanding as of December 31, 2013)

 

216

 

2,093

 

Subordinated unitholders (4,480,000 units issued and outstanding as of June 30, 2014 and 6,720,000 units issued and outstanding as of December 31, 2013)

 

556

 

8,572

 

Total unitholders’ equity

 

176,969

 

192,258

 

TOTAL LIABILITIES AND UNITHOLDERS’ EQUITY

 

$

481,045

 

$

488,350

 

 

See accompanying notes to the unaudited consolidated condensed financial statements.

 

1



Table of Contents

 

LRR Energy, L.P.

Consolidated Condensed Statements of Operations

(Unaudited)

(in thousands, except per unit amounts)

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

Revenues:

 

 

 

 

 

 

 

 

 

Oil sales

 

$

20,354

 

$

19,012

 

$

40,510

 

$

34,475

 

Natural gas sales

 

7,565

 

7,720

 

15,664

 

13,800

 

Natural gas liquids sales

 

2,760

 

2,275

 

6,124

 

4,510

 

Gain (loss) on commodity derivative instruments, net

 

(13,328

)

12,354

 

(18,950

)

6,287

 

Other income

 

40

 

18

 

71

 

87

 

Total revenues

 

17,391

 

41,379

 

43,419

 

59,159

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

Lease operating expense

 

6,829

 

5,270

 

12,664

 

12,067

 

Production and ad valorem taxes

 

2,248

 

2,198

 

4,648

 

4,044

 

Depletion and depreciation

 

8,680

 

10,129

 

17,145

 

20,239

 

Accretion expense

 

510

 

477

 

1,013

 

947

 

Loss (gain) on settlement of asset retirement obligations

 

21

 

360

 

61

 

335

 

General and administrative expense

 

2,699

 

2,768

 

5,881

 

6,197

 

Total operating expenses

 

20,987

 

21,202

 

41,412

 

43,829

 

 

 

 

 

 

 

 

 

 

 

Operating income (loss)

 

(3,596

)

20,177

 

2,007

 

15,330

 

 

 

 

 

 

 

 

 

 

 

Other income (expense), net

 

 

 

 

 

 

 

 

 

Interest expense

 

(2,575

)

(2,249

)

(5,116

)

(4,514

)

Gain (loss) on interest rate derivative instruments, net

 

(1,128

)

2,657

 

(1,422

)

2,772

 

Other income (expense), net

 

(3,703

)

408

 

(6,538

)

(1,742

)

 

 

 

 

 

 

 

 

 

 

Income (loss) before taxes

 

(7,299

)

20,585

 

(4,531

)

13,588

 

Income tax expense

 

(38

)

(62

)

(112

)

(67

)

Net income (loss)

 

$

(7,337

)

$

20,523

 

$

(4,643

)

$

13,521

 

Net loss (income) attributable to common control operations

 

 

 

 

(448

)

Net income (loss) available to unitholders

 

$

(7,337

)

$

20,523

 

$

(4,643

)

$

13,073

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General partner’s interest in net income (loss)

 

$

(7

)

$

21

 

$

(4

)

$

13

 

 

 

 

 

 

 

 

 

 

 

Limited partners’ interest in net income (loss)

 

$

(7,330

)

$

20,502

 

$

(4,639

)

$

13,060

 

 

 

 

 

 

 

 

 

 

 

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

 

$

(0.27

)

$

0.78

 

$

(0.17

)

$

0.53

 

 

 

 

 

 

 

 

 

 

 

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

 

26,733

 

26,169

 

26,539

 

24,555

 

 

See accompanying notes to the unaudited consolidated condensed financial statements.

 

2



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, 2013

 

$

303

 

$

181,290

 

$

2,093

 

$

8,572

 

$

192,258

 

Equity offering, net of expenses

 

 

14,810

 

 

 

14,810

 

Amortization of equity awards

 

 

534

 

 

 

534

 

Conversion of subordinated units

 

 

 

623

 

(623

)

 

Distribution

 

(22

)

(17,548

)

(1,832

)

(6,588

)

(25,990

)

Net income (loss)

 

(4

)

(3,166

)

(668

)

(805

)

(4,643

)

Balance, June 30, 2014

 

$

277

 

$

175,920

 

$

216

 

$

556

 

$

176,969

 

 

See accompanying notes to the unaudited consolidated condensed financial statements.

 

3



Table of Contents

 

LRR Energy, L.P.

Consolidated Condensed Statements of Cash Flows

(Unaudited)

(in thousands)

 

 

 

Six Months Ended June 30,

 

 

 

2014

 

2013

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income (loss)

 

$

(4,643

)

$

13,521

 

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

 

 

 

 

 

Depletion and depreciation

 

17,145

 

20,239

 

Accretion expense

 

1,013

 

947

 

Amortization of equity awards

 

534

 

253

 

Amortization of derivative contracts

 

330

 

508

 

Amortization of deferred financing costs and other

 

208

 

187

 

Loss (gain) on settlement of asset retirement obligations

 

61

 

335

 

Changes in operating assets and liabilities:

 

 

 

 

 

Change in receivables

 

75

 

(2,568

)

Change in prepaid expenses

 

(209

)

(279

)

Change in derivative assets and liabilities

 

20,605

 

(3,163

)

Change in amounts due to/from affiliates

 

(5,992

)

(5,446

)

Change in accrued liabilities and deferred tax liabilities

 

2,536

 

2,581

 

Net cash provided by (used in) operating activities

 

31,663

 

27,115

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Development of oil and natural gas properties

 

(17,094

)

(14,375

)

Disposition of oil and natural gas properties

 

65

 

 

Net cash provided by (used in) investing activities

 

(17,029

)

(14,375

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Borrowings under revolving credit facility

 

20,000

 

38,000

 

Principal payments on revolving credit facility

 

(25,000

)

(24,000

)

Equity offering, net of expenses

 

14,810

 

59,513

 

Distributions

 

(25,990

)

(23,422

)

Distribution to Lime Rock Resources

 

 

(60,672

)

Contribution to Lime Rock Resources

 

 

(734

)

Net cash provided by (used in) financing activities

 

(16,180

)

(11,315

)

 

 

 

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

 

(1,546

)

1,425

 

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD

 

4,417

 

3,467

 

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS, END OF PERIOD

 

$

2,871

 

$

4,892

 

 

 

 

 

 

 

Supplemental disclosure of non-cash items to reconcile investing and financing activities

 

 

 

 

 

Property and equipment:

 

 

 

 

 

Accrued capital costs

 

$

1,735

 

$

4,662

 

Asset retirement obligations

 

(181

)

(313

)

 

See accompanying notes to the unaudited consolidated condensed financial statements.

 

4



Table of Contents

 

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 will be 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/combined financial statements in our Annual Report on Form 10-K for the year ended December 31, 2013 (“2013 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/combined financial statements and notes in our 2013 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/combined financial statements in our 2013 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.

 

Certain reclassifications were made to the historical financial statements to conform to the 2014 presentation. The effects of the reclassification were not material to our unaudited interim consolidated condensed financial statements.

 

Recent accounting pronouncements

 

On May 28, 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“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 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

 

5



Table of Contents

 

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.

 

3.              Acquisitions

 

Acquisition between Entities under Common Control

 

On January 3, 2013, we completed an acquisition from Fund I of certain oil and natural gas properties located in the Mid-Continent region in Oklahoma for a purchase price of $21.0 million, subject to customary purchase price adjustments (the “January 2013 Acquisition”). In addition, as part of the January 2013 Acquisition, we acquired in the money commodity hedge contracts valued at approximately $1.7 million as of the closing of the January 2013 Acquisition. The January 2013 Acquisition was effective October 1, 2012. In June 2013, we paid $0.4 million in cash to Fund I related to post-closing adjustments to the purchase price. We funded the January 2013 Acquisition with borrowings under our revolving credit facility (Note 7).

 

The following table presents the net assets conveyed by Fund I to us in the January 2013 Acquisition (in thousands):

 

Property and equipment, net

 

$

23,998

 

Oil and natural gas commodity hedge contracts

 

1,742

 

Asset retirement obligations and other liabilities

 

(1,067

)

Net assets

 

$

24,673

 

 

On April 1, 2013, we completed an acquisition of certain oil and natural gas properties located in the Mid-Continent region in Oklahoma and crude oil hedges from Fund II for a purchase price of $38.2 million (the “April 2013 Acquisition”). As part of the April 2013 Acquisition, we acquired in the money crude oil hedges valued at approximately $0.4 million as of the closing of the April 2013 Acquisition. The April 2013 Acquisition was effective April 1, 2013. We funded the April 2013 Acquisition with proceeds from our equity offering (Note 10).

 

The following table presents the net assets conveyed by Fund II to us in the April 2013 Acquisition (in thousands):

 

Property and equipment, net

 

$

36,586

 

Oil and natural gas commodity hedge contracts

 

386

 

Asset retirement obligations and other liabilities

 

(990

)

Net assets

 

$

35,982

 

 

The net assets of the January 2013 Acquisition and April 2013 Acquisition were recorded using carryover book value of Fund I and Fund II, as the acquisitions were deemed transactions between entities under common control. Our historical financial statements were revised to include the results attributable to previous acquisitions from Fund I and Fund II as if we owned the properties for all periods presented in our consolidated condensed financial statements.

 

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

 

6



Table of Contents

 

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 June 30, 2014 and December 31, 2013 (in thousands).

 

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

June 30, 2014

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

$

 

$

13,591

 

$

 

$

13,591

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

 

9,426

 

 

9,426

 

Interest rate derivative instruments

 

 

3,219

 

 

3,219

 

December 31, 2013

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

$

 

$

26,472

 

$

 

$

26,472

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

 

2,391

 

 

2,391

 

Interest rate derivative instruments

 

 

2,202

 

 

2,202

 

 

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.

 

7



Table of Contents

 

5.              Property and Equipment

 

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

 

 

 

June 30, 2014

 

December 31, 2013

 

 

 

 

 

 

 

Oil and natural gas properties (successful efforts method)

 

$

893,825

 

$

875,126

 

Unproved properties

 

1,238

 

1,258

 

Other property and equipment

 

289

 

290

 

 

 

895,352

 

876,674

 

Accumulated depletion, depreciation and impairment

 

(449,054

)

(431,837

)

Total property and equipment, net

 

$

446,298

 

$

444,837

 

 

We recorded $8.7 million and $10.1 million of depletion and depreciation expense for the three months ended June 30, 2014 and 2013, respectively. We recorded $17.1 million and $20.2 million of depletion and depreciation expense for the six months ended June 30, 2014 and 2013, respectively.

 

We perform an impairment analysis of our oil and natural gas properties on a quarterly basis due to the volatility in commodity prices. We did not record any impairment charges in the three or six months ended June 30, 2014 or 2013. If future oil or natural gas prices or our reserves decline, the estimated undiscounted future cash flows for the 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 six months ended June 30, 2014 (in thousands):

 

Beginning of period

 

$

36,326

 

Dispositions

 

(84

)

Liabilities incurred

 

181

 

Accretion expense

 

1,013

 

End of period

 

37,436

 

Current portion of asset retirement obligations

 

(503

)

Asset retirement obligations — non-current

 

$

36,933

 

 

7.              Long-Term Debt

 

Credit Agreement

 

In July 2011, subject to consummation of our initial public offering, we, as guarantor, and our wholly owned subsidiary, OLLC, as borrower, entered into a five-year, $500.0 million senior secured revolving credit facility, as amended (the “Credit Agreement”), that matures in July 2016. 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 $235.0 million as of June 30, 2014. 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 at their sole discretion. As of June 30, 2014, we were in compliance with all covenants contained in the Credit Agreement.

 

Term Loan Agreement

 

On June 28, 2012, we, as parent guarantor, and our wholly owned subsidiary, OLLC, as borrower, entered into a Second Lien Credit Agreement (the “Term Loan Agreement”). The Term Loan Agreement provides for a $50.0 million senior secured second lien term loan to OLLC. OLLC borrowed $50.0 million under the Term Loan Agreement and used the borrowings to repay outstanding borrowings under the Credit Agreement. As of June 30, 2014, we were in compliance with all covenants contained in the Term Loan Agreement. The Term Loan Agreement was amended in June 2014 (Note 10).

 

8



Table of Contents

 

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 June 30, 2014, we had $245.0 million of outstanding debt and accrued interest was approximately $0.2 million. As of December 31, 2013, we had $250.0 million of outstanding debt and accrued interest was approximately $0.2 million.

 

Interest expense for the three months ended June 30, 2014 and 2013 was $2.6 million and $2.2 million, respectively. Interest expense for the six months ended June 30, 2014 and 2013 was $5.1 million and $4.5 million, respectively. As of June 30, 2014 and December 31, 2013, our weighted average interest rate on our outstanding indebtedness was 4.21% and 3.88%, 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.

 

Our open positions typically consist of contracts such as (i) crude oil and natural gas financial collar contracts, (ii) crude oil, natural gas liquids (“NGL”) and natural gas financial swaps, (iii) crude oil and natural gas basis financial swaps, (iv) crude oil and natural gas puts and (v) interest rate swap agreements. Our derivative instruments are with the counterparties that are also lenders in our Credit Agreement.

 

Swaps and options are used to manage our exposure to commodity price risk and basis risk inherent in our oil and natural gas production. Commodity price swap agreements are used to fix the price of expected future oil and natural gas sales at major industry trading locations such as Henry Hub Louisiana (“HH”) for gas and Cushing Oklahoma (“WTI”) for oil. Basis swaps are used to fix the price differential between the product price at one location versus another. Options are used to establish a floor and a ceiling price (collar) for expected oil or gas sales. Interest rate swaps are used to fix interest rates on existing indebtedness.

 

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. A collar is a combination of a put purchased by us and a call option written by us. In a typical collar transaction, if the floating price based on a market index is below the floor price, we receive from the counterparty an amount equal to this difference multiplied by the specified volume, effectively a put option. If the floating price exceeds the floor price and is less than the ceiling price, no payment is required by either party. If the floating price exceeds the ceiling price, we must pay the counterparty an amount equal to the difference multiplied by the specific quantity, effectively a call option.

 

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.

 

9



Table of Contents

 

We elected not to designate any positions as cash flow hedges for accounting purposes and, accordingly, recorded the net change in the mark-to-market valuation of these derivative contracts in the consolidated condensed statements of operations. We record our derivative activities on a mark-to-market or fair value basis. Fair values are based on pricing models that consider various assumptions, including quoted forward prices for commodities, the time value of money and volatility, and are comparable to values obtained from counterparties. We present the fair value of derivative financial instruments on a net basis in the consolidated condensed balance sheets.

 

At June 30, 2014, we had the following open commodity derivative contracts:

 

 

 

Index

 

2014

 

2015

 

2016

 

2017

 

Natural gas positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (MMBTUs)

 

NYMEX-HH

 

2,961,198

 

5,500,236

 

5,433,888

 

5,045,760

 

Weighted average price

 

 

 

$

5.56

 

$

5.72

 

$

4.29

 

$

4.61

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps (MMBTUs)

 

(1)

 

2,860,739

 

5,326,559

 

2,877,047

 

 

Weighted average price

 

 

 

$

(0.1530

)

$

(0.1661

)

$

(0.1115

)

$

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (BBLs)

 

NYMEX-WTI

 

378,675

 

683,286

 

397,488

 

198,744

 

Weighted average price

 

 

 

$

96.18

 

$

93.39

 

$

86.02

 

$

85.75

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps (BBLs)

 

Argus-

 

195,605

 

 

 

 

Weighted average price

 

Midland-Cushing

 

$

(1.00

)

$

 

$

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (BBLs)

 

Mont Belvieu

 

137,760

 

236,149

 

 

 

Weighted average price

 

 

 

$

34.72

 

$

34.46

 

$

 

$

 

 


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

 

At December 31, 2013, we had the following open commodity derivative contracts:

 

 

 

Index

 

2014

 

2015

 

2016

 

2017

 

Natural gas positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (MMBTUs)

 

NYMEX-HH

 

6,077,016

 

5,500,236

 

5,433,888

 

5,045,760

 

Weighted average price

 

 

 

$

5.53

 

$

5.72

 

$

4.29

 

$

4.61

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps (MMBTUs)

 

(1)

 

5,876,098

 

5,326,559

 

2,877,047

 

 

Weighted average price

 

 

 

$

(0.1521

)

$

(0.1661

)

$

(0.1115

)

$

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (BBLs)

 

NYMEX-WTI

 

723,634

 

561,833

 

397,488

 

198,744

 

Weighted average price

 

 

 

$

95.76

 

$

93.16

 

$

86.02

 

$

85.75

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps (BBLs)

 

Argus-

 

410,400

 

 

 

 

Weighted average price

 

Midland-Cushing

 

$

(1.00

)

$

 

$

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (BBLs)

 

Mont Belvieu

 

183,857

 

147,823

 

 

 

Weighted average price

 

 

 

$

34.11

 

$

34.50

 

$

 

$

 

 


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

 

10



Table of Contents

 

At June 30, 2014 and December 31, 2013, 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 June 30, 2014

 

 

 

Current

 

Long-term

 

Current

 

Long-term

 

 

 

Assets

 

Assets

 

Liabilities

 

Liabilities

 

Interest rate

 

 

 

 

 

 

 

 

 

Swaps

 

$

 

$

 

 

$

1,304

 

$

1,915

 

Gross fair value

 

 

 

 

1,304

 

1,915

 

Netting arrangements

 

 

 

 

 

 

Net recorded fair value

 

$

 

$

 

$

1,304

 

$

1,915

 

 

 

 

 

 

 

 

 

 

 

Sale of natural gas production

 

 

 

 

 

 

 

 

 

Price swaps

 

$

7,374

 

$

5,563

 

$

240

 

$

3

 

Basis swaps

 

2

 

49

 

413

 

379

 

Sale of crude oil production

 

 

 

 

 

 

 

 

 

Price swaps

 

40

 

458

 

4,621

 

3,629

 

Basis swaps

 

648

 

 

 

 

Sale of NGLs

 

 

 

 

 

 

 

 

 

Price swaps

 

65

 

4

 

616

 

137

 

Gross fair value

 

8,129

 

6,074

 

5,890

 

4,148

 

Netting arrangements

 

(107

)

(505

)

(107

)

(505

)

Net recorded fair value

 

$

8,022

 

$

5,569

 

$

5,783

 

$

3,643

 

 

 

 

As of December 31, 2013

 

 

 

Current

 

Long-term

 

Current

 

Long-term

 

 

 

Assets

 

Assets

 

Liabilities

 

Liabilities

 

Interest rate

 

 

 

 

 

 

 

 

 

Swaps

 

$

 

$

637

 

$

648

 

$

2,191

 

Gross fair value

 

 

637

 

648

 

2,191

 

Netting arrangements

 

 

(637

)

 

(637

)

Net recorded fair value

 

$

 

$

 

$

648

 

$

1,554

 

 

 

 

 

 

 

 

 

 

 

Sale of natural gas production

 

 

 

 

 

 

 

 

 

Price swaps

 

$

8,250

 

$

11,937

 

$

196

 

$

73

 

Basis swaps

 

56

 

211

 

317

 

65

 

Sale of crude oil production

 

 

 

 

 

 

 

 

 

Price swaps

 

1,564

 

5,042

 

1,519

 

331

 

Basis swaps

 

227

 

 

 

 

Sale of NGLs

 

 

 

 

 

 

 

 

 

Price swaps

 

106

 

4

 

662

 

153

 

Gross fair value

 

10,203

 

17,194

 

2,694

 

622

 

Netting arrangements

 

(477

)

(448

)

(477

)

(448

)

Net recorded fair value

 

$

9,726

 

$

16,746

 

$

2,217

 

$

174

 

 

11



Table of Contents

 

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 June 30,

 

Six Months Ended June 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

Commodity derivatives (revenue)

 

$

(13,328

)

$

12,354

 

$

(18,950

)

$

6,287

 

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

 

(1,128

)

2,657

 

(1,422

)

2,772

 

 

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 June 30, 2014, 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 18.0% of our outstanding common units and all of our subordinated units, representing an approximate 31.5% limited partner interest in us. As of June 30, 2014, 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.

 

As more fully described in our 2013 Annual Report, three separate one-third tranches of the subordinated units may convert on the first business day after the distribution to unitholders in respect of any quarter ending on or after December 31, 2012, December 31, 2013 and December 31, 2014, respectively, provided that an aggregate amount equal to the minimum quarterly distribution payable with respect to all units that would be payable on four, eight or twelve consecutive quarters, as applicable, has been earned and paid prior to the applicable date, in each case provided there are no arrearages in the minimum quarterly distribution on our common units at that time. 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 do not expect the second tranche of the subordinated units to convert pursuant to the provisions of our partnership agreement following our distribution for the second quarter of 2014 that will be paid on August 14, 2014. Each quarter, we will determine whether the test for conversion of the subordinated units has been met until the subordinated units convert pursuant to the provisions of our partnership agreement.

 

Contracts with our General Partner and its Affiliates

 

As more fully described in our 2013 Annual Report, we have entered into agreements with our general partner and its affiliates. For the three months ended June 30, 2014 and 2013, we paid Lime Rock Management approximately $0.4 million and $0.2 million either directly or indirectly related to these agreements, respectively. For the six months ended June 30, 2014 and 2013, we paid Lime Rock Management approximately $0.6 million and $0.5 million either directly or indirectly related to these agreements, respectively.

 

12



Table of Contents

 

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 six months ended June 30, 2014 are included below (in thousands):

 

 

 

 

 

Lime Rock

 

 

 

 

 

ServCo

 

Resources

 

Total

 

 

 

 

 

 

 

 

 

Balance as of December 31, 2013

 

$

(518

)

$

263

 

$

(255

)

Expenditures

 

(51,549

)

 

(51,549

)

Cash paid for expenditures

 

66,718

 

 

66,718

 

Revenues and other

 

(9,175

)

(2

)

(9,177

)

Balance as of June 30, 2014

 

$

5,476

 

$

261

 

$

5,737

 

 

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 June 30, 2014, our general partner and its affiliates held 4,089,600 of our common units, all of our subordinated units and 22,400 general partner units. During the six months ended June 30, 2014 and 2013, we paid cash distributions of $26.0 million and $23.4 million, respectively, to all unitholders as of the respective record dates.

 

We announced our second quarter 2014 distribution on July 18, 2014 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. 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, 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. On June 6, 2014, we entered into an amendment to our Term Loan to waive this requirement through September 30, 2014. During the six months ended June 30, 2014, we received net proceeds from the sale of 885,135 newly issued common units of $14.8 million, after deducting underwriting discounts and commissions and offering expenses of approximately $0.5 million, and used the proceeds for general partnership purposes. During the six months ended June 30, 2014, we paid approximately $0.3 million of aggregate compensation to MLV for sales under the ATM Program.

 

Equity Offering

 

On March 22, 2013, we closed a public equity offering of 3,700,000 common units representing limited partner interests in the Partnership at a price to the public of $16.84 per common unit, or $16.1664 per common unit after payment of the underwriting discount. We received net proceeds from the sale of 3,700,000 newly issued common units of $59.5 million, after deducting underwriting discounts and commissions and offering expenses of $0.3 million. We used the net proceeds of the offering to fund our April 2013 Acquisition discussed in Note 3 and repay borrowings outstanding on our Credit Agreement.

 

Fund I sold 3,200,000 common units in the equity offering at a price to the public of $16.84 per common unit, or $16.1664 per common unit after payment of the underwriting discount. We did not receive any proceeds from the sale of common units by Fund I; however, the equity balance of Fund I was adjusted for its reduced ownership interest in us.

 

13



Table of Contents

 

Units Outstanding

 

As of June 30, 2014, we had 22,674,390 common units, 4,480,000 subordinated units and 22,400 general partner units outstanding. As of June 30, 2014, Fund I owned 4,089,600 common units and all of our subordinated units, representing an approximate 31.5% limited partner interest in us.

 

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 June 30,

 

Six Months Ended June 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(7,337

)

$

20,523

 

$

(4,643

)

$

13,521

 

Net income (loss) attributable to common control operations

 

 

 

 

(448

)

Net income (loss) available to unitholders

 

(7,337

)

20,523

 

(4,643

)

13,073

 

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

 

7

 

(21

)

4

 

(13

)

Limited partners’ interest in net income (loss)

 

$

(7,330

)

$

20,502

 

$

(4,639

)

$

13,060

 

 

 

 

 

 

 

 

 

 

 

Weighted average limited partner units outstanding:

 

 

 

 

 

 

 

 

 

Common units

 

21,121

 

19,449

 

20,376

 

17,835

 

Subordinated units

 

5,612

 

6,720

 

6,163

 

6,720

 

Total

 

26,733

 

26,169

 

26,539

 

24,555

 

 

 

 

 

 

 

 

 

 

 

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

 

$

(0.27

)

$

0.78

 

$

(0.17

)

$

0.53

 

 

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 approximate 0.1% interest in net income (loss), by the weighted average number of common units and subordinated units outstanding as of June 30, 2014 and 2013. The aggregate number of common units and subordinated units outstanding was 22,674,390 and 4,480,000, respectively, as of June 30, 2014. The aggregate number of common units and subordinated units outstanding was 19,448,539 and 6,720,000, respectively, as of June 30, 2013.

 

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 June 30, 2014, there were 1,308,345 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.

 

14



Table of Contents

 

A summary of the status of the non-vested restricted units as of June 30, 2014, is presented below:

 

 

 

Number of

 

Weighted Average

 

 

 

Non-vested

 

Grant-Date

 

 

 

Restricted Units

 

Fair Value

 

Non-vested restricted units at December 31, 2013

 

165,262

 

$

 

Granted

 

3,012

 

16.60

 

Vested

 

(12,341

)

17.92

 

Forfeited

 

(13,691

)

16.54

 

Non-vested restricted units at June 30, 2014

 

142,242

 

 

 

As of June 30, 2014, there was approximately $2.1 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 2.2 years. There were 49,410 vested restricted units as of June 30, 2014.

 

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 of 1933. 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 July 18, 2014, we announced that the board of directors of our general partner declared a cash distribution for the second quarter of 2014 of $0.4950 per outstanding unit, or $1.98 on an annualized basis. The distribution will be paid on August 14, 2014 to all unitholders of record as of the close of business on July 31, 2014. The aggregate amount of the distribution will be $13.6 million.

 

Commodity Hedges

 

Subsequent to June 30, 2014, we acquired the following commodity hedges:

 

 

 

Index

 

2015

 

 

 

 

 

 

 

Oil positions

 

 

 

 

 

Basis swaps (BBLs)

 

Argus-

 

397,035

 

Weighted average price

 

Midland-Cushing

 

$

(3.41

)

 

15



Table of Contents

 

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, 2013 (“2013 Annual Report”) that 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 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 in our credit facility and term loan;

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

·                  electronic, cyber, and physical security breaches;

·                  general economic conditions; and

 

16



Table of Contents

 

·                  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.

 

Contribution of Properties

 

On January 3, 2013, we completed an acquisition from Fund I of certain oil and natural gas properties located in the Mid-Continent region in Oklahoma for a purchase price of $21.0 million, subject to customary purchase price adjustments (the “January 2013 Acquisition”). In addition, as part of the January 2013 Acquisition, we acquired in the money commodity hedge contracts valued at approximately $1.7 million at the closing of the January 2013 Acquisition. The January 2013 Acquisition was effective October 1, 2012. In June 2013, we paid $0.4 million in cash to Fund I related to post-closing adjustments to the purchase price.

 

On April 1, 2013, we completed an acquisition of certain oil and natural gas properties located in the Mid-Continent region in Oklahoma and crude oil hedges from Fund II for a purchase price of $38.2 million (the “April 2013 Acquisition”). As part of the April 2013 Acquisition, we acquired in the money crude oil hedges valued at approximately $0.4 million as of the closing of the April 2013 Acquisition. The April 2013 Acquisition was effective April 1, 2013. We funded the April 2013 Acquisition with proceeds from our equity offering described in Note 10 to the consolidated condensed financial statements included in this report.

 

Results of Operations

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

Revenues (in thousands):

 

 

 

 

 

 

 

 

 

Oil sales

 

$

20,354

 

$

19,012

 

$

40,510

 

$

34,475

 

Natural gas sales

 

7,565

 

7,720

 

15,664

 

13,800

 

Natural gas liquids sales

 

2,760

 

2,275

 

6,124

 

4,510

 

Gain (loss) on commodity derivative instruments, net

 

(13,328

)

12,354

 

(18,950

)

6,287

 

Other income

 

40

 

18

 

71

 

87

 

Total revenues

 

17,391

 

41,379

 

43,419

 

59,159

 

 

17



Table of Contents

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

Expenses (in thousands):

 

 

 

 

 

 

 

 

 

Lease operating expense

 

6,829

 

5,270

 

12,664

 

12,067

 

Production and ad valorem taxes

 

2,248

 

2,198

 

4,648

 

4,044

 

Depletion and depreciation

 

8,680

 

10,129

 

17,145

 

20,239

 

General and administrative expense

 

2,699

 

2,768

 

5,881

 

6,197

 

Interest expense

 

2,575

 

2,249

 

5,116

 

4,514

 

Loss (gain) on interest rate derivative instruments, net

 

1,128

 

(2,657

)

1,422

 

(2,772

)

 

 

 

 

 

 

 

 

 

 

Production:

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

216

 

210

 

434

 

398

 

Natural gas (MMcf)

 

1,666

 

1,843

 

3,288

 

3,651

 

NGLs (MBbls)

 

90

 

73

 

175

 

145

 

Total (MBoe)

 

584

 

590

 

1,157

 

1,152

 

Average net production (Boe/d)

 

6,418

 

6,484

 

6,392

 

6,365

 

 

 

 

 

 

 

 

 

 

 

Average sales price:

 

 

 

 

 

 

 

 

 

Oil (per Bbl):

 

 

 

 

 

 

 

 

 

Sales price

 

$

94.23

 

$

90.53

 

$

93.34

 

$

86.62

 

Effect of settled commodity derivative instruments

 

(3.50

)

0.39

 

(2.14

)

0.80

 

Realized price

 

$

90.73

 

$

90.92

 

$

91.20

 

$

87.42

 

Natural gas (per Mcf):

 

 

 

 

 

 

 

 

 

Sales price

 

$

4.54

 

$

4.19

 

$

4.76

 

$

3.78

 

Effect of settled commodity derivative instruments

 

0.71

 

0.87

 

0.62

 

1.41

 

Realized price

 

$

5.25

 

$

5.06

 

$

5.38

 

$

5.19

 

NGLs (per Bbl):

 

 

 

 

 

 

 

 

 

Sales price

 

$

30.67

 

$

31.16

 

$

34.99

 

$

31.10

 

Effect of settled commodity derivative instruments

 

(1.81

)

6.26

 

(2.77

)

5.49

 

Realized price

 

$

28.86

 

$

37.42

 

$

32.22

 

$

36.59

 

 

 

 

 

 

 

 

 

 

 

Average unit cost per Boe:

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

11.70

 

$

8.93

 

$

10.95

 

$

10.48

 

Production and ad valorem taxes

 

3.85

 

3.72

 

4.02

 

3.51

 

Depletion and depreciation

 

14.87

 

17.16

 

14.82

 

17.58

 

General and administrative expenses

 

4.62

 

4.69

 

5.08

 

5.38

 

 

Our Results for the Three Months Ended June 30, 2014 Compared to the Three Months Ended June 30, 2013

 

We recorded a net loss of $7.3 million for the three months ended June 30, 2014 compared to net income of $20.5 million during the three months ended June 30, 2013, primarily related to losses on commodity derivative instruments, higher lease operating expenses, offset by increased revenues and lower depletion and depreciation expense. 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 June 30, 2013 and June 30, 2014 follows (in thousands):

 

Oil, natural gas and NGL revenues-prior period

 

$

29,007

 

Increase (decrease)

 

 

 

Price realization

 

 

 

Oil

 

777

 

Natural gas

 

645

 

NGLs

 

(36

)

Sales volumes

 

 

 

Oil

 

565

 

Natural gas

 

(800

)

NGLs

 

521

 

Oil, natural gas and NGL revenues-current period

 

$

30,679

 

 

18



Table of Contents

 

Sales revenues increased from $29.0 million for the three months ended June 30, 2013 to $30.7 million for the three months ended June 30, 2014, primarily due to higher commodity price realizations and oil and NGL sales volumes offset by lower natural gas volumes. Sales revenues for the three months ended June 30, 2014 consisted of oil sales of $20.3 million, natural gas sales of $7.6 million and NGL sales of $2.8 million. Sales revenues for the three months ended June 30, 2013 consisted of oil sales of $19.0 million, natural gas sales of $7.7 million and NGL sales of $2.3 million.

 

Our production volumes for the three months ended June 30, 2014 included 306 MBbls of oil and NGLs and 1,666 MMcf of natural gas, or 3,363 Bbl/d of oil and NGLs and 18,308 Mcf/d of natural gas. On an equivalent basis, production for the period was 584 MBoe, or 6,418 Boe/d. Our average net production for the three months ended June 30, 2014 was negatively impacted by flaring at the Red Lake field of approximately 30 Boe/d due to third-party compression limits. Our production volumes for the three months ended June 30, 2013 included 283 MBbls of oil and NGLs and 1,843 MMcf of natural gas, or 3,110 Bbl/d of oil and NGLs and 20,253 Mcf/d of natural gas. On an equivalent basis, production for the period was 590 MBoe, or 6,484 Boe/d.  Our average net production for the three months ended June 30, 2013 was negatively impacted by flaring at the Red Lake field of approximately 90 Boe/d due to third-party compression limits.

 

Our average sales price per Bbl for oil and NGLs for the three months ended June 30, 2014, excluding the effect of commodity derivative contracts, was $94.23 and $30.67, respectively. Our average sales price per Mcf of natural gas for the three months ended June 30, 2014, excluding the effect of commodity derivative contracts, was $4.54. Our average sales price per Bbl for oil and NGLs for the three months ended June 30, 2013, excluding the effect of commodity derivative contracts, was $90.53 and $31.16, respectively. Our average sales price per Mcf of natural gas for the three months ended June 30, 2013, excluding the effect of commodity derivative contracts, was $4.19.

 

Effects of Commodity Derivative Contracts.  Due to changes in oil and natural gas prices, we recorded a net loss from our commodity hedging program for the three months ended June 30, 2014 of $13.3 million, which was comprised of positive net cash settlements and amortization of purchases of approximately $0.3 million and declines in the fair value of derivatives of approximately $13.6 million. For the three months ended June 30, 2013, we recorded a net gain from our commodity hedging program of $12.3 million, which was comprised of positive net cash settlements and amortization of approximately $2.1 million and positive fluctuations in fair value of derivatives of approximately $10.2 million. Volatility in commodity prices has had a significant impact on our gains and losses on commodity derivative contracts.

 

Lease Operating Expense.  Our lease operating expenses were $6.8 million, or $11.70 per Boe, for the three months ended June 30, 2014 compared to $5.3 million, or $8.93 per Boe, for the three months ended June 30, 2013. The primary driver of the increased lease operating expenses was higher costs at our Red Lake field associated with the increased development activity and production offset by lower workover expenses.

 

Production and Ad Valorem Taxes.  Our production and ad valorem taxes were $2.2 million, or $3.85 per Boe, for the three months ended June 30, 2014 compared to $2.2 million, or $3.72 per Boe, for the three months ended June 30, 2013. Production taxes accounted for approximately $2.1 million and ad valorem taxes for approximately $0.1 million of the total taxes recorded during the three months ended June 30, 2014. Production taxes accounted for approximately $2.0 million and ad valorem taxes for approximately $0.2 million of the total taxes recorded during the three months ended June 30, 2013.

 

Depletion and Depreciation.  Our depletion and depreciation expense was $8.7 million, or $14.87 per Boe, for the three months ended June 30, 2014 compared to $10.1 million, or $17.16 per Boe, for the three months ended June 30, 2013. The decrease in depletion and depreciation expense and per Boe amounts was primarily related lower property and equipment balances as of June 30, 2014.

 

Impairment of Oil and Natural Gas Properties.  We did not record an impairment charge in the three months ended June 30, 2014 and 2013. If future oil or natural gas prices or reserves decline, 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 July 31, 2014, the NYMEX-WTI oil spot price was $98.17 per Bbl and the NYMEX-Henry Hub natural gas spot price was $3.74 per MMBtu.

 

19



Table of Contents

 

General and Administrative Expenses.  Our general and administrative expenses were $2.7 million, or $4.62 per Boe, for the three months ended June 30, 2014 compared to $2.8 million, or $4.69 per Boe, for the three months ended June 30, 2013.

 

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 $2.6 million and $2.2 million for the three months ended June 30, 2014 and 2013, respectively.

 

Effects of Interest Rate Derivatives. Loss on interest rate derivative contracts, net, was $1.1 million for the three months ended June 30, 2014, including $0.2 million in negative cash settlements and $0.9 million in declines in fair value of the derivatives. Gain on interest rate derivative contracts, net, was $2.7 million for the three months ended June 30, 2013, including $0.2 million in negative cash settlements and $2.9 million in positive fluctuations in fair value of the derivatives.

 

Our Results for the Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013

 

We recorded a net loss of $4.6 million for the six months ended June 30, 2014 compared to net income of $13.5 million during the six months ended June 30, 2013, primarily related to losses on commodity derivative instruments, net and higher operating expenses, offset by increased revenues and lower depletion and depreciation expense. 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 six months ended June 30, 2013 and June 30, 2014 follows (in thousands):

 

Oil, natural gas and NGL revenues-prior period

 

$

52,785

 

Increase (decrease)

 

 

 

Price realization

 

 

 

Oil

 

2,675

 

Natural gas

 

3,592

 

NGLs

 

564

 

Sales volumes

 

 

 

Oil

 

3,360

 

Natural gas

 

(1,728

)

NGLs

 

1,050

 

Oil, natural gas and NGL revenues-current period

 

$

62,298

 

 

Sales revenues increased from $52.8 million for the six months ended June 30, 2013 to $62.3 million for the six months ended June 30, 2014, primarily due to higher commodity price realizations and oil and NGL sales volumes offset by lower natural gas volumes. Sales revenues for the six months ended June 30, 2014 consisted of oil sales of $40.5 million, natural gas sales of $15.7 million and NGL sales of $6.1 million. Sales revenues for the six months ended June 30, 2013 consisted of oil sales of $34.5 million, natural gas sales of $13.8 million and NGL sales of $4.5 million.

 

Our production volumes for the six months ended June 30, 2014 included 609 MBbls of oil and NGLs and 3,288 MMcf of natural gas, or 3,365 Bbl/d of oil and NGLs and 18,166 Mcf/d of natural gas. On an equivalent basis, production for the period was 1,157 MBoe, or 6,392 Boe/d. Our average net production for the six months ended June 30, 2014 was negatively impacted by flaring at the Red Lake field of approximately 50 Boe/d due to third-party compression limits. Our production volumes for the six months ended June 30, 2013 included 543 MBbls of oil and NGLs and 3,651 MMcf of natural gas, or 3,000 Bbl/d of oil and NGLs and 20,171 Mcf/d of natural gas. On an equivalent basis, production for the period was 1,152 MBoe, or 6,365 Boe/d. Our average net production for the six months ended June 30, 2013 was negatively impacted by flaring at the Red Lake field of approximately 80 Boe/d due to third-party compression limits.

 

20



Table of Contents

 

Our average sales price per Bbl for oil and NGLs for the six months ended June 30, 2014, excluding the effect of commodity derivative contracts, was $93.34 and $34.99, respectively. Our average sales price per Mcf of natural gas for the six months ended June 30, 2014, excluding the effect of commodity derivative contracts, was $4.76. Our average sales price per Bbl for oil and NGLs for the six months ended June 30, 2013, excluding the effect of commodity derivative contracts, was $86.62 and $31.10, respectively. Our average sales price per Mcf of natural gas for the six months ended June 30, 2013, excluding the effect of commodity derivative contracts, was $3.78.

 

Effects of Commodity Derivative Contracts.  Due to changes in oil and natural gas prices, we recorded a net loss from our commodity hedging program for the six months ended June 30, 2014 of $18.9 million, which was comprised of positive net cash settlements and amortization of purchases of approximately $0.6 million and declines in the fair value of derivatives of approximately $19.5 million. For the six months ended June 30, 2013, we recorded a net gain from our commodity hedging program of $6.3 million, which was comprised of positive net cash settlements and amortization of approximately $6.3 million and positive fluctuations in fair value of derivatives of less than $0.1 million. Volatility in commodity prices has had a significant impact on our gains and losses on commodity derivative contracts.

 

Lease Operating Expense.  Our lease operating expenses were $12.7 million, or $10.95 per Boe, for the six months ended June 30, 2014 compared to $12.1 million, or $10.48 per Boe, for the six months ended June 30, 2013. Lease operating expenses increased by approximately $1.5 million primarily due to increased development activity and production at the Red Lake field offset by lower workover expenses of approximately $0.9 million.

 

Production and Ad Valorem Taxes.  Our production and ad valorem taxes were $4.6 million, or $4.02 per Boe, for the six months ended June 30, 2014 compared to $4.0 million, or $3.51 per Boe, for the six months ended June 30, 2013. The increase in production and ad valorem taxes was primarily due to increased severance taxes at the Red Lake field. Production taxes accounted for approximately $4.3 million and ad valorem taxes for $0.3 million of the total taxes recorded during the six months ended June 30, 2014. Production taxes accounted for approximately $3.6 million and ad valorem taxes for $0.4 million of the total taxes recorded during the six months ended June 30, 2013.

 

Depletion and Depreciation.  Our depletion and depreciation expense was $17.1 million, or $14.82 per Boe, for the six months ended June 30, 2014 compared to $20.2 million, or $17.58 per Boe, for the six months ended June 30, 2013. The decrease in depletion and depreciation expense and per Boe amounts was primarily related lower property and equipment balances as of June 30, 2014.

 

Impairment of Oil and Natural Gas Properties.  We did not record an impairment charge in the six months ended June 30, 2014 and 2013. If future oil or natural gas prices or reserves decline, 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 July 31, 2014, the NYMEX-WTI oil spot price was $98.17 per Bbl and the NYMEX-Henry Hub natural gas spot price was $3.74 per MMBtu.

 

General and Administrative Expenses.  Our general and administrative expenses were $5.9 million, or $5.08 per Boe, for the six months ended June 30, 2014 compared to $6.2 million, or $5.38 per Boe, for the six months ended June 30, 2013.

 

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 $5.1 million and $4.5 million for the six months ended June 30, 2014 and 2013, respectively.

 

Effects of Interest Rate Derivatives. Loss on interest rate derivative contracts, net, was $1.4 million for the six months ended June 30, 2014, including $0.4 million in negative cash settlements and $1.0 million in declines in fair value of the derivatives. Gain on interest rate derivative contracts, net, was $2.8 million for the six months ended June 30, 2013, including $0.3 million in negative cash settlements and $3.1 million in positive fluctuations in fair value of the derivatives.

 

21



Table of Contents

 

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.

 

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 June 30, 2014 and 2013 was $19.6 million and $21.3 million, respectively. The decrease was primarily driven by higher lease operating expenses. Our Adjusted EBITDA for the six months ended June 30, 2014 and 2013 was $40.7 million and $37.6 million, respectively. The increase was primarily driven by higher revenues.

 

Our Distributable Cash Flow for the three months ended June 30, 2014 and 2013 was $11.8 million and $13.9 million, respectively. The decrease in Distributable Cash Flow was driven by the decreased Adjusted EBITDA as discussed above and increased cash interest expense. Our Distributable Cash Flow for the six months ended June 30, 2014 and 2013 was $25.2 million and $22.7 million, respectively. The increase in Distributable Cash Flow was driven by the increased Adjusted EBITDA as discussed above offset by increased cash interest expense.

 

22



Table of Contents

 

Reconciliation of Adjusted EBITDA and Distributable Cash Flow to Net Income (Loss)

 

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

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

(in thousands)

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(7,337

)

$

20,523

 

$

(4,643

)

$

13,521

 

Income tax expense

 

38

 

62

 

112

 

67

 

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

 

3,703

 

(408

)

6,538

 

1,742

 

Depletion and depreciation

 

8,680

 

10,129

 

17,145

 

20,239

 

Accretion of asset retirement obligations

 

510

 

477

 

1,013

 

947

 

Amortization of equity awards

 

249

 

138

 

534

 

253

 

Loss (gain) on settlement of asset retirement obligations

 

21

 

360

 

61

 

335

 

Loss (gain) on commodity derivative instruments, net

 

13,328

 

(12,354

)

18,950

 

(6,287

)

Commodity derivative instrument net cash settlements

 

444

 

2,404

 

967

 

6,756

 

Impairment of oil and natural gas properties

 

 

 

 

 

Adjusted EBITDA

 

$

19,636

 

$

21,331

 

$

40,677

 

$

37,573

 

 

 

 

 

 

 

 

 

 

 

Adjusted EBITDA

 

19,636

 

21,331

 

40,677

 

37,573

 

Income tax expense

 

(44

)

(47

)

(88

)

(73

)

Cash interest expense

 

(2,757

)

(2,314

)

(5,401

)

(4,616

)

Estimated maintenance capital (1)

 

(5,000

)

(5,075

)

(10,000

)

(10,150

)

Distributable cash flow

 

$

11,835

 

$

13,895

 

$

25,188

 

$

22,734

 

 


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

 

Liquidity and Capital Resources

 

Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements 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 flows generated by operating activities and borrowings under our credit facility and term loan and equity offerings under our recently established “at-the-market” offering program (the “ATM Program”), described below. We may issue additional equity and debt as needed.

 

On February 4, 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. 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 six months ended June 30, 2014, we received net proceeds from the sale of 885,135 newly issued common units of $14.8 million, after deducting underwriting discounts and commissions and offering expenses of $0.5 million, and used the proceeds for general partnership purposes. During the six months ended June 30, 2014, we paid approximately $0.3 million of aggregate compensation to MLV for sales under the ATM Program.

 

23



Table of Contents

 

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. On June 6, 2014, we entered into an amendment to our term loan to waive this requirement through September 30, 2014.

 

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.

 

We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.4750 per unit per quarter ($1.90 per unit on an annualized basis). Based on the number of common units, subordinated units and general partner units outstanding as of July 31, 2014, quarterly distributions to all of our unitholders at our current quarterly distribution rate would total $13.6 million.

 

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, and we intend to use primarily external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, rather than cash reserves established by our general partner, to make acquisitions to further increase our production and proved reserves. Because our proved reserves and production decline continually over time and because we do not own any undeveloped properties or leasehold acreage, we will need to make acquisitions to sustain our level of distributions to unitholders over time.

 

If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures, reduce distributions to unitholders, and/or fund a portion of our capital expenditures using borrowings under our credit facility or term loan, issuances of debt and equity securities or from other sources, such as asset sales. Our ability to raise funds through the incurrence of additional indebtedness could be limited by the covenants in our credit facility and term loan. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.

 

As of June 30, 2014, we had borrowing capacity of $40.0 million under our $500.0 million revolving credit facility ($235.0 million borrowing base less $195.0 million of outstanding borrowings) and $2.9 million of cash on hand. As of June 30, 2014, we had no available borrowing capacity under our $50.0 million term loan.

 

24



Table of Contents

 

Based upon current oil and natural gas price expectations and our commodity derivatives positions at June 30, 2014, which cover 86% of our estimated production from total proved developed producing reserves, we anticipate that our cash on hand, cash flow from operations, proceeds from our ATM Program and available borrowing capacity under our revolving credit facility will provide us sufficient working capital to fund our total planned 2014 capital expenditures and annualized cash distributions as described above.

 

We expect to spend $37.5 million in total capital expenditures in 2014, of which $20.0 million represents maintenance capital expenditures on the development of our existing oil and natural gas properties.

 

We intend to pursue acquisitions of long-lived, low-risk producing oil and natural gas properties with reserve exploitation potential. We would expect to finance any significant acquisition of oil and natural gas properties in 2014 through external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equity securities, including through our ATM Program.

 

Credit Agreement

 

In July 2011, subject to consummation of our initial public offering, we, as guarantor, and our wholly owned subsidiary, LRE Operating, LLC (“OLLC”), as borrower, entered into a five-year, $500.0 million senior secured revolving credit facility, as amended (the “Credit Agreement”), that matures in July 2016. 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 $235.0 million as of June 30, 2014. Our borrowing base, which is primarily based on the estimated value of our oil 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.

 

A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we could be required to pledge other oil and natural gas properties as additional collateral. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our Credit Agreement. Additionally, we will not be able to pay distributions to our unitholders in any such quarter in the event there exists a borrowing base deficiency or an event of default either before or after giving effect to such distribution or we are not in pro forma compliance with the Credit Agreement after giving effect to such distribution.

 

If we fail to perform our obligations under the covenants described in our 2013 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 June 30, 2014, we were in compliance with our covenants contained in the Credit Agreement.

 

At June 30, 2014, we had $195.0 million of outstanding borrowings under our Credit Agreement and available borrowing capacity of $40.0 million. As of July 31, 2014, we had approximately $190.0 million of outstanding borrowings under our Credit Agreement and available borrowing capacity of approximately $45.0 million.

 

Term Loan Agreement

 

On June 28, 2012, we, as parent guarantor, and our wholly owned subsidiary, OLLC, as borrower, entered into a Second Lien Credit Agreement (the “Term Loan Agreement”). The Term Loan Agreement provides for a $50.0 million senior secured second lien term loan to OLLC. OLLC borrowed $50.0 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 2013 Annual Report. As of June 30, 2014, we were in compliance with all covenants contained in the Term Loan Agreement.

 

25



Table of Contents

 

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 and collars in place as of June 30, 2014. The weighted average price is based on the swap price for oil, NGL and natural gas swaps and the floor price of oil and natural gas collars. We use swaps and collars 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.

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

$

96.18

 

2,058

 

$

34.72

 

749

 

$

5.56

 

16,093

 

2015

 

$

93.39

 

1,872

 

$

34.46

 

647

 

$

5.72

 

15,069

 

2016

 

$

86.02

 

1,089

 

$

 

 

$

4.29

 

14,887

 

2017

 

$

85.75

 

545

 

$

 

 

$

4.61

 

13,824

 

 

The following table summarizes, for the periods presented, our natural gas basis swaps in place as of June 30, 2014. 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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

$

(0.2131

)

6,268

 

$

(0.0839

)

3,317

 

$

(0.1291

)

5,070

 

$

(0.1229

)

892

 

2015

 

$

(0.2291

)

5,939

 

$

(0.0959

)

3,031

 

$

(0.1380

)

4,777

 

$

(0.1334

)

846

 

2016

 

$

 

 

$

(0.0810

)

2,691

 

$

(0.1326

)

4,408

 

$

(0.0975

)

784

 

 

The following table summarizes, for the periods presented, our oil basis swaps in place as of June 30, 2014. 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.

 

 

 

Argus –
Midland-Cushing

 

Term

 

$/Bbl

 

Bbl/d

 

 

 

 

 

 

 

2014

 

$

(1.00

)

1,063

 

 

Cash Flows

 

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

 

 

 

Six Months Ended June 30,

 

 

 

2014

 

2013

 

 

 

 

 

 

 

Net cash provided by (used in):

 

 

 

 

 

Operating activities

 

$

31,663

 

$

27,115

 

Investing activities

 

(17,029

)

(14,375

)

Financing activities

 

(16,180

)

(11,315

)

 

26



Table of Contents

 

Operating Activities.

 

Net cash provided by operating activities was $31.7 million and $27.1 million for the six months ended June 30, 2014 and 2013, 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 $11.6 million and $17.1 million at June 30, 2014 and December 31, 2013, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $2.9 million and $4.4 million at June 30, 2014 and December 31, 2013, respectively.

 

Investing Activities.

 

Net cash used in investing activities was $17.0 million and $14.4 million for the six months ended June 30, 2014 and 2013, respectively, which primarily represented additions to our property and equipment balances during the periods.

 

Financing Activities.

 

Cash flows used in financing activities was $16.2 million for the six months ended June 30, 2014, and consisted of net proceeds received from an equity offering of $14.8 million offset by distributions to unitholders of $26.0 million and net repayments on the Credit Agreement of $5.0 million.

 

Cash flows used in financing activities was approximately $11.3 million for the six months ended June 30, 2013, which consisted of net proceeds from the March 2013 equity offering of $59.5 million and net borrowings of $14.0 million offset by distributions paid to our unitholders of $23.4 million and contributions and distributions to Lime Rock Resources of $61.4 million.

 

Off-Balance Sheet Arrangements

 

As of June 30, 2014, 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 2013 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 2013 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

 

27



Table of Contents

 

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 June 30, 2014.

 

Changes in Internal Control over Financial Reporting

 

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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.

 

There have been no material changes to the risk factors described in our 2013 Annual Report.

 

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).

 

28



Table of Contents

 

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).

 

 

 

10.1

 

Third Amendment dated as of June 6, 2014 to Second Lien Credit Agreement dated as of June 28, 2012, among LRE Operating, LLC, as Borrower, LRR Energy, L.P., as Parent Guarantor, the lenders from time to time party thereto and Wells Fargo Energy Capital, Inc., as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on June 11, 2014).

 

 

 

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

 

29



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: August 6, 2014

 

By:

/s/ Eric Mullins

 

 

 

Eric Mullins

 

 

 

Co-Chief Executive Officer

 

 

 

 

 

 

Date: August 6, 2014

 

By:

/s/ Jaime R. Casas

 

 

 

Jaime R. Casas

 

 

 

Vice President, Chief Financial Officer and Secretary

 

 

 

(Principal Financial Officer)

 

30



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).

 

 

 

10.1

 

Third Amendment dated as of June 6, 2014 to Second Lien Credit Agreement dated as of June 28, 2012, among LRE Operating, LLC, as Borrower, LRR Energy, L.P., as Parent Guarantor, the lenders from time to time party thereto and Wells Fargo Energy Capital, Inc., as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on June 11, 2014).

 

 

 

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