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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 September 30, 2011

 

OR

 

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

 

For the transition period from           to           .

 

Commission File Number:  001-35344

 

LRR Energy, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware

 

90-0708431

(State or other jurisdiction of
incorporation or organization)

 

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

 

Heritage Plaza

1111 Bagby, Suite 4600

Houston, Texas

 

77002

(Address of principal executive offices)

 

(Zip code)

 

Telephone Number:  (713) 292-9510

(Registrant’s telephone number, including area code)

 


 

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

 

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  o

 

 

 

Non-accelerated filer  x

 

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 15,700,074 Common Units, 6,720,000 Subordinated Units and 22,400 General Partner Units outstanding as of December 19, 2011.  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 Combined Condensed Balance Sheets of Lime Rock Resources Fund I (Predecessor of LRR Energy, L.P.) as of September 30, 2011 and December 31, 2010

 

1

 

Unaudited Combined Condensed Statements of Operations of Lime Rock Resources Fund I (Predecessor of LRR Energy, L.P.) for the Three and Nine Months Ended September 30, 2011 and 2010

 

2

 

Unaudited Combined Condensed Statements of Changes in Partners’ Capital of Lime Rock Resources Fund I (Predecessor of LRR Energy, L.P.) as of September 30, 2011

 

3

 

Unaudited Combined Condensed Statements of Cash Flows of Lime Rock Resources Fund I (Predecessor of LRR Energy, L.P.) for the Nine Months Ended September 30, 2011 and 2010

 

4

 

Notes to Unaudited Combined Condensed Financial Statements of Lime Rock Resources Fund I (Predecessor of LRR Energy, L.P.)

 

5

Item 2.

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

 

17

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.

 

29

Item 4.

(Removed and Reserved).

 

29

Item 5.

Other Information.

 

29

Item 6.

Exhibits.

 

29

 

Signatures

 

32

 

Explanatory Note

 

The information contained in this report relates to periods that ended prior to the completion of the initial public offering of LRR Energy, L.P., and prior to the effective dates of the agreements discussed herein.  Consequently, the unaudited combined condensed financial statements and related discussion of financial condition and results of operations contained in this report pertain to 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”, collectively with LRR A and LRR B, “Fund I” or “predecessor”).  Because the results of our predecessor include results for both the properties conveyed to us in connection with our IPO and properties retained by our predecessor, we do not consider these results of our predecessor to be indicative of our future results.  In connection with the closing of the initial public offering, LRR Energy, L.P. entered into a purchase, sale, contribution, conveyance and assumption agreement with Fund I pursuant to which LRR Energy, L.P. acquired specified oil and natural gas properties and related net profits interests and operations in exchange for newly issued limited partner interests in LRR Energy, L.P and cash consideration.  See Note 1 to the unaudited combined condensed financial statements for information regarding the initial public offering.

 

i



Table of Contents

 

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

 

Lime Rock Resources Fund I (Predecessor of LRR Energy, L.P.)

Combined Condensed Balance Sheets

(Unaudited)

 

 

 

September 30, 2011

 

December 31, 2010

 

 

 

(in thousands)

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

5,716

 

$

12,455

 

Accounts receivable

 

16,524

 

16,543

 

Commodity derivative instruments

 

22,448

 

23,819

 

Amounts due from affiliates

 

 

59

 

Prepaid expenses

 

1,238

 

1,722

 

Total current assets

 

45,926

 

54,598

 

 

 

 

 

 

 

Property and equipment (successful efforts method)

 

822,492

 

784,346

 

Accumulated depletion, depreciation and impairment

 

(391,142

)

(342,400

)

Total property and equipment, net

 

431,350

 

441,946

 

 

 

 

 

 

 

Commodity derivative instruments

 

30,327

 

7,767

 

Deferred financing costs, net of accumulated amortization

 

252

 

311

 

TOTAL ASSETS

 

$

507,855

 

$

504,622

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Trade accounts payable

 

$

7,257

 

$

3,354

 

Accrued liabilities

 

6,984

 

8,141

 

Accrued capital cost

 

5,089

 

6,620

 

Commodity derivative instruments

 

1,109

 

1,888

 

Due to affiliates

 

196

 

 

Interest rate derivative instruments

 

480

 

594

 

Asset retirement obligations

 

333

 

792

 

Total current liabilities

 

21,448

 

21,389

 

 

 

 

 

 

 

Long-term liabilities:

 

 

 

 

 

Commodity derivative instruments

 

1,157

 

5,333

 

Interest rate derivative instruments

 

84

 

267

 

Revolving credit facility

 

27,251

 

27,251

 

Asset retirement obligations

 

25,159

 

23,504

 

Deferred tax liabilities

 

64

 

145

 

Total long-term liabilities

 

53,715

 

56,500

 

Total liabilities

 

75,163

 

77,889

 

 

 

 

 

 

 

Partners’ capital:

 

432,692

 

426,733

 

 

 

 

 

 

 

TOTAL LIABILITIES AND PARTNERS’ CAPITAL

 

$

507,855

 

$

504,622

 

 

See accompanying notes to the unaudited combined condensed financial statements

 

1



Table of Contents

 

Lime Rock Resources Fund I (Predecessor of LRR Energy, L.P.)

Combined Condensed Statements of Operations

(Unaudited)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

 

 

Oil sales

 

$

16,677

 

$

13,573

 

$

51,338

 

$

39,542

 

Natural gas sales

 

9,699

 

12,330

 

31,453

 

37,516

 

Natural gas liquids sales

 

4,508

 

3,057

 

12,266

 

10,488

 

Realized gain on commodity derivative instruments

 

6,029

 

12,186

 

6,070

 

35,450

 

Unrealized gain (loss) on commodity derivative instruments

 

29,253

 

(4,542

)

26,144

 

(2,502

)

Other income

 

42

 

31

 

122

 

77

 

Total revenues

 

66,208

 

36,635

 

127,393

 

120,571

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

6,797

 

4,917

 

18,732

 

15,360

 

Production and ad valorem taxes

 

2,711

 

1,822

 

5,731

 

6,889

 

Depletion and depreciation

 

11,163

 

16,102

 

32,034

 

45,686

 

Impairment of oil and natural gas properties

 

16,765

 

 

16,765

 

10,944

 

Accretion expense

 

368

 

343

 

1,112

 

1,012

 

Loss on settlement of asset retirement obligations

 

39

 

 

39

 

 

Management fees

 

1,579

 

1,534

 

4,546

 

5,337

 

General and administrative expenses

 

1,208

 

659

 

4,414

 

4,331

 

Total operating expenses

 

40,630

 

25,377

 

83,373

 

89,559

 

 

 

 

 

 

 

 

 

 

 

Operating income

 

25,578

 

11,258

 

44,020

 

31,012

 

 

 

 

 

 

 

 

 

 

 

Other income (expense), net:

 

 

 

 

 

 

 

 

 

Interest income

 

 

3

 

1

 

8

 

Interest expense

 

(255

)

(281

)

(814

)

(1,009

)

Realized loss on interest rate derivative instruments

 

(141

)

(164

)

(439

)

(488

)

Unrealized gain (loss) on interest rate derivative instruments

 

134

 

(115

)

297

 

(447

)

Other income (expense), net

 

(262

)

(557

)

(955

)

(1,936

)

 

 

 

 

 

 

 

 

 

 

Income before taxes

 

25,316

 

10,701

 

43,065

 

29,076

 

 

 

 

 

 

 

 

 

 

 

Income tax benefit (expense)

 

266

 

(62

)

120

 

(3

)

 

 

 

 

 

 

 

 

 

 

Net income

 

$

25,582

 

$

10,639

 

$

43,185

 

$

29,073

 

 

See accompanying notes to the unaudited combined condensed financial statements

 

2



Table of Contents

 

Lime Rock Resources Fund I (Predecessor of LRR Energy, L.P.)

Combined Condensed Statements of Changes in Partners’ Capital

(Unaudited)

 

 

 

 

 

 

 

Class B

 

 

 

 

 

General

 

Limited

 

Limited

 

 

 

 

 

Partner

 

Partners

 

Partner

 

Total

 

 

 

(in thousands)

 

Balance, December 31, 2010

 

$

3,452

 

$

268,108

 

$

155,173

 

$

426,733

 

Capital Contributions

 

70

 

5,283

 

 

5,353

 

Distributions

 

(471

)

(35,295

)

(6,813

)

(42,579

)

Net income

 

596

 

35,776

 

6,813

 

43,185

 

Balance, September 30, 2011

 

$

3,647

 

$

273,872

 

$

155,173

 

$

432,692

 

 

See accompanying notes to the unaudited combined condensed financial statements

 

3



Table of Contents

 

Lime Rock Resources Fund I (Predecessor of LRR Energy, L.P.)

Combined Condensed Statements of Cash Flows

(Unaudited)

 

 

 

Nine Months Ended September 30,

 

 

 

2011

 

2010

 

 

 

(in thousands)

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income

 

$

43,185

 

$

29,073

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

Depletion and depreciation

 

32,034

 

45,686

 

Impairment of oil and natural gas properties

 

16,765

 

10,944

 

Unrealized loss (gain) on derivative instruments, net

 

(26,441

)

2,949

 

Accretion expense

 

1,112

 

1,012

 

Amortization of deferred financing costs and other

 

59

 

93

 

Loss on settlement of asset retirement obligations

 

39

 

 

Changes in operating assets and liabilities:

 

 

 

 

 

Change in receivables

 

19

 

(1,440

)

Change in prepaid expenses

 

484

 

3,434

 

Change in trade accounts payable and accrued liabilities

 

2,665

 

(1,588

)

Change in amounts due from affiliates

 

255

 

623

 

Net cash provided by operating activities

 

70,176

 

90,786

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Acquisition of oil and natural gas properties

 

(390

)

(104,147

)

Development of oil and natural gas properties

 

(42,210

)

(23,846

)

Disposition of oil and natural gas properties

 

2,956

 

 

Expenditures for other property and equipment

 

(45

)

(35

)

Net cash used in investing activities

 

(39,689

)

(128,028

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Deferred financing costs

 

 

(29

)

Borrowings under revolving credit facility

 

 

3,713

 

Capital contributions

 

5,353

 

125,475

 

Distributions

 

(42,579

)

(80,463

)

Capital contributions returned

 

 

(9,318

)

Net cash provided by (used in) financing activities

 

(37,226

)

39,378

 

 

 

 

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

 

(6,739

)

2,136

 

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD

 

12,455

 

15,527

 

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS, END OF PERIOD

 

$

5,716

 

$

17,663

 

 

 

 

 

 

 

Supplemental disclosure of non-cash items to reconcile:

 

 

 

 

 

Investing and financing activities

 

 

 

 

 

Property and equipment:

 

 

 

 

 

Change in accrued capital costs

 

$

1,531

 

$

165

 

Asset retirement obligations

 

84

 

2,993

 

 

See accompanying notes to the unaudited combined condensed financial statements

 

4



Table of Contents

 

Lime Rock Resources Fund I (Predecessor of LRR Energy, L.P.)

Notes to Unaudited Combined Condensed Financial Statements

 

1.              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” or “predecessor” refer collectively to LRR A, LRR B and LRR C.  References to “Lime Rock Resources” refer collectively to LRR A, LRR B, LRR C, Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P.  The properties conveyed to us in connection with our initial public offering (“IPO”) (such conveyance described below) 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”).

 

Prior to and as of September 30, 2011, Fund I owned 100% of the properties conveyed to us in connection with our IPO.  On November 16, 2011, we completed our IPO of 9,408,000 common units representing limited partner interests in the Partnership at a price to the public of $19.00 per common unit, or $17.8125 per common unit after payment of the underwriting discount.  At the closing of our IPO, we entered into a purchase, sale, contribution, conveyance and assumption agreement with Fund I pursuant to which Fund I sold and contributed to us specified oil and natural gas properties and related net profits interests and operations and certain commodity derivative contracts covering approximately 85% of our estimated production from total proved developed producing reserves for each of the years ending December 31, 2011 through 2015 based on production estimates in our reserve reports as of March 31, 2011 (the “Common Control Properties”).   Fund I received 6,249,600 common units, 6,720,000 subordinated units representing limited partner interests in us, and $289.9 million in cash in exchange for these contributions to the Partnership.

 

Fund I is under common control with us.  Because the Common Control Properties are deemed to be under common control, accounting rules specify that Fund I and the Common Control Properties be combined from the earliest date they came under common control.

 

The accompanying unaudited combined condensed financial statements of Fund I reflect the predecessor financial statements of the Partnership and have been prepared from the separate financial records maintained by Fund I.  Because the results of our predecessor include results for both the properties conveyed to us in connection with our IPO and properties retained by our predecessor, we do not consider these results of our predecessor to be indicative of our future results.  Prior to such contribution, our financial statements consisted of total assets of $1,000 and we had not conducted any activity from our formation in April 2011 through September 30, 2011.  In addition, the effects of our IPO, related equity transfers and debt transactions that occurred in November 2011 are not reflected in these unaudited combined condensed financial statements.  See Note 10 for further discussion regarding the completion of our IPO and other related items occurring subsequent to the period ended September 30, 2011.

 

2.              Summary of Significant Accounting Policies

 

The accounting policies followed by the predecessor are set forth in Note 2 of the audited combined financial statements for the year ended December 31, 2010 included in our final prospectus dated November 10, 2011 (the “Prospectus”) included in our Registration Statement on Form S-1, as amended (SEC File No. 333-174017), and are supplemented by the notes to these unaudited combined condensed financial statements.  There have been no significant changes to these policies and these unaudited combined condensed financial statements should be read in conjunction with the audited combined financial statements and notes for the year ended December 31, 2010 included in the Prospectus.

 

5



Table of Contents

 

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 combined financial statements and should be read in conjunction with the audited combined financial statements of our predecessor for the year ended December 31, 2010 included in our Prospectus.  While the year-end 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 combined financial statements reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for the periods presented.

 

Recent accounting pronouncements

 

In January 2010, the FASB issued Accounting Standards Update (“ASU”) 2010-06, “Improving Disclosures about Fair Value Measurements” (“ASU 2010-06”), which amends the Fair Value Measurements and Disclosures Topic of the Accounting Standards Codification (“ASC Topic 820”).  Among other provisions, ASC Topic 820 establishes a fair value hierarchy that prioritizes the relative reliability of inputs used in fair value measurements. The hierarchy gives highest priority to Level 1 inputs that represent unadjusted quoted market prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are directly or indirectly observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs and have the lowest priority in the hierarchy.  This amendment requires new disclosures on the value of, and the reason for, transfers in and out of Levels 1 and 2 of the fair value hierarchy and additional disclosures about purchases, sales, issuances and settlements within Level 3 fair value measurements.  ASU 2010-06 also clarifies existing disclosure requirements on levels of disaggregation and about inputs and valuation techniques.  ASU 2010-06 was effective for interim and annual reporting periods beginning after December 15, 2009, except for the requirement to provide additional disclosures regarding Level 3 measurements which is effective for interim and annual reporting periods beginning after December 15, 2010.   The additional disclosure requirements of ASU 2010-06 are included in the footnotes of these unaudited combined condensed financial statements.

 

3.              Acquisitions and Divestitures

 

The predecessor acquires proved oil and natural gas properties that meet management’s criteria with respect to reserve lives, development potential, production risk and other operational characteristics. The predecessor generally does not acquire assets other than oil and natural gas property interests. The predecessor assumes the liability for asset retirement obligations (“ARO”) related to each acquisition and records the liability at fair value as of the date of closing.

 

The operating revenues and expenses of acquired properties are included in the predecessor’s combined financial statements from the acquisition date. Transactions are financed through partner contributions and borrowings.

 

The 2010 acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, the predecessor conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while acquisition costs associated with the acquisitions were expensed as incurred. The predecessor did not acquire proved oil and natural gas properties during the nine months ended September 30, 2011.

 

The fair values of oil and natural gas properties and ARO are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate.

 

6



Table of Contents

 

2010 acquisitions

 

On February 23, 2010, the predecessor completed an acquisition of interests in 51 producing gas wells located in Oklahoma (Potato Hills) from a private independent oil and gas company for approximately $104.0 million in cash, subject to customary post-closing and title adjustments. Total proved reserves of the acquired properties were estimated at 10.0 million barrels of oil equivalent at the date of the acquisition.

 

On August 31, 2010, the predecessor completed the acquisition of certain oil and natural gas properties located in Texas from a private independent oil and gas company for a purchase price of approximately $7.5 million, subject to customary post-closing and title adjustments.

 

The following table summarizes the values assigned to the assets acquired and liabilities assumed as of the acquisition date:

 

 

 

Potato

 

Other

 

Total 2010

 

 

 

Hills

 

Acquisition

 

Acquisitions

 

 

 

(in thousands)

 

Oil and natural gas properties

 

$

97,488

 

$

6,659

 

$

104,147

 

Asset retirement obligations assumed

 

(1,927

)

(1,066

)

(2,993

)

Identifiable net assets

 

$

95,561

 

$

5,593

 

$

101,154

 

 

These acquisitions qualify as business combinations, and as such, the predecessor estimated the fair value of these properties as of the acquisition dates.  The fair value is 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 (exit price).  Fair value measurements also utilize assumptions of market participants.  In the estimation of fair value, the predecessor used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates.  These assumptions represent Level 3 inputs, as further discussed under Note 4 — Fair Value Measurements.  After post-closing and title adjustments, the assets acquired and liabilities assumed approximate fair value for the acquisition.

 

Summarized below are the combined results of operations for the three and nine months ended September 30, 2010, on an unaudited pro forma basis, as if the 2010 acquisitions had occurred on January 1, 2010:

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30, 2010

 

September  30, 2010

 

 

 

Actual

 

Pro Forma

 

Actual

 

Pro Forma

 

 

 

(in thousands)

 

Revenue

 

$

36,635

 

$

38,375

 

$

120,571

 

$

126,077

 

Net Income

 

10,639

 

11,904

 

29,073

 

33,233

 

 

2011 and 2010 divestitures of non-core assets

 

In May 2011, the predecessor sold its interests in certain oil and natural gas properties located in New Mexico to a third party for $2.9 million, subject to customary closing adjustments.

 

In both 2011 and 2010, the sales of these non-core assets did not affect the unit-of-production amortization rate and, therefore, no gain or loss was recognized for the divestitures.

 

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4.              Fair Value Measurements

 

The predecessor’s financial instruments, including cash and cash equivalents, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments.  The predecessor’s financial and non-financial assets and liabilities that are being measured on a recurring basis are measured and reported at fair value.

 

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  GAAP establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).  The three levels of fair value hierarchy are as follows:

 

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

 

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

 

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

 

As required by GAAP, the predecessor utilizes 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 the predecessor’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2011 and December 31, 2010.

 

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

 

 

(in thousands)

 

September 30, 2011

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

$

 

$

 

$

52,775

 

$

52,775

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

 

 

2,266

 

2,266

 

Interest rate derivative instruments

 

 

 

564

 

564

 

December 31, 2010

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

$

 

$

 

$

31,586

 

$

31,586

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

 

 

7,221

 

7,221

 

Interest rate derivative instruments

 

 

 

861

 

861

 

 

All fair values reflected in the table above and on the unaudited combined 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.

 

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The curves are obtained from independent pricing services reflecting broker market quotes.

 

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three and nine months ended September 30, 2011 and 2010:

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

(in thousands)

 

Balance at beginning of period

 

$

20,558

 

$

49,424

 

$

23,504

 

$

47,716

 

Total gains or losses (realized or unrealized):

 

 

 

 

 

 

 

 

 

Included in earnings

 

35,275

 

7,365

 

32,072

 

32,013

 

Settlements

 

(5,888

)

(12,022

)

(5,631

)

(34,962

)

Transfers in and out of Level 3

 

 

 

 

 

Balance at end of period

 

$

49,945

 

$

44,767

 

$

49,945

 

$

44,767

 

Changes in unrealized gains (losses) relating to derivatives still held at end of period

 

$

29,387

 

$

(4,657

)

$

26,441

 

$

(2,949

)

 

5.              Property and Equipment

 

The components of property and equipment, net follow:

 

 

 

September 30, 2011

 

December 31, 2010

 

 

 

(in thousands)

 

Oil and natural gas properties (successful efforts method)

 

$

819,855

 

$

781,495

 

Unproved properties

 

1,872

 

2,133

 

Other property and equipment

 

765

 

718

 

 

 

822,492

 

784,346

 

Accumulated depletion, depreciation and impairment

 

(391,142

)

(342,400

)

Total property and equipment, net

 

$

431,350

 

$

441,946

 

 

For the nine months ended September 30, 2011 and 2010, due to a significant decline in future natural gas price curves across all future production periods, the predecessor performed an impairment analysis of its oil and natural gas properties and other non-current assets. For the nine months ended September 30, 2011, the predecessor recorded a total non-cash impairment charge of approximately $16.8 million to impair the value of its proved oil and natural gas properties in the Mid-Continent region.  For the nine months ended September 30, 2010, the predecessor recorded a total non-cash impairment charge of approximately $10.9 million to impair the value of its proved oil and natural gas properties in the Gulf Coast region. These non-cash charges are included in “Impairment of oil and natural gas properties” in the Combined Condensed Statements of Operations. These impairments of proved oil and natural gas properties were recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash flows reported in a third-party reserve report. This report was based upon future oil and natural gas prices, which are based on observable inputs adjusted for basis differentials, which are Level 3 inputs. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the predecessor’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. Furthermore, significant assumptions in valuing the proved reserves included the reserve quantities, anticipated drilling and operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated drilling schedules, anticipated production declines, and an appropriate discount rate commensurate with the risk of the underlying cash flow estimates. Cash flow estimates for the impairment testing excluded derivative instruments

 

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used to mitigate the risk of lower future natural gas prices. These asset impairments had no impact on the predecessor’s cash flows, liquidity position, or debt covenants. If expected future oil and natural gas prices decline or we experience a loss of reserves during the last quarter of 2011 or future periods, the estimated undiscounted future cash flows for the proved oil and natural gas properties may not exceed the net capitalized costs for the predecessor’s 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 the predecessor’s ARO as of and for the nine months ended September 30, 2011:

 

 

 

(in thousands)

 

Beginning of period

 

$

24,296

 

Assumed in acquisitions

 

586

 

Divested properties

 

 

Revisions to previous estimates

 

 

Liabilities incurred

 

 

Liabilities settled

 

(502

)

Accretion expense

 

1,112

 

End of period

 

25,492

 

Less: Current portion of asset retirement obligations

 

333

 

Asset retirement obligations — non-current

 

$

25,159

 

 

7.              Long-Term Debt

 

On February 2, 2006, LRR A entered into a $45 million credit facility that was syndicated to a group of lenders. On November 23, 2010, this credit facility was refinanced, and LRR A entered into a new $45 million credit facility that was syndicated to essentially the same group of lenders and with substantively the same material terms and conditions as the previous credit facility. In addition, certain interest rate swap instruments were novated and amended because the composition of lenders in the syndicate group changed. The amended and novated interest rate swap agreements are as follows:

 

 

 

Instrument

 

Notional

 

Average

 

 

 

Maturity

 

Type

 

Amount

 

%

 

Index

 

Feb 2013

 

Swaps

 

$

5,135,000

 

2.266

%

LIBOR

 

 

As of September 30, 2011, LRR A’s availability under the credit facility was restricted to the borrowing base of $31.5 million. The borrowing base is subject to review and adjustment on a semiannual basis and other interim adjustments as requested by the lenders or LRR A, as applicable. At the election of LRR A, amounts outstanding under the credit facility bear interest at specified margins over LIBOR of 2.00% to 2.75% or specified margins over an Alternate Base Rate of 1.00% to 1.75%. The Alternate Base Rate is the greatest of the Prime Rate, the Fed Funds Rate plus 1/2 of 1%, or the adjusted LIBOR for a one-month Interest Period plus 1%. Such margins will fluctuate based on the utilization of the facility. As of September 30, 2011, the interest rate on LRR A’s revolving line of credit, taking into account the predecessor’s interest rate swaps, was an average of 4.75%.

 

Borrowings under the credit facility are collateralized by a perfected, first-priority security interest in substantially all of the oil and natural gas properties owned by LRR A. LRR A is subject to financial covenants with respect to current ratio, interest coverage ratio, and ratio of debt to EBITDAX. EBITDAX is defined as net income plus interest, income taxes, depreciation, depletion, amortization, exploration expenses, and other noncash charges, and minus all noncash income. If a material acquisition (as defined in the credit facility) is made during the quarter, the credit facility provides that the EBITDAX be calculated giving pro forma effect as if such acquisition occurred on the first day of such quarter. In addition, LRR A is subject to covenants limiting restricted payments, transactions with affiliates, incurrence of debt, asset sales, and liens on properties. Except for the current ratio covenant, LRR A was in compliance with all of the financial covenants as of September 30, 2011.  LRR A received a waiver for non-compliance with this covenant.

 

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All amounts drawn under the credit facility are due and payable on November 23, 2014. As of September 30, 2011 and December 31, 2010, borrowings under the credit facility were $27.3 million and accrued interest payable was $0.1 million.

 

8.              Derivatives

 

Objective and strategy — The predecessor is exposed to commodity price and interest rate risk and considers it prudent to periodically reduce the predecessor’s exposure to cash flow variability resulting from commodity price changes and interest rate fluctuations. Accordingly, the predecessor enters into derivative instruments to manage its 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.

 

At September 30, 2011 and December 31, 2010, the predecessor’s open positions consisted of (i) crude oil and natural gas financial collar contracts, (ii) crude oil and natural gas financial swaps, (iii) natural gas basis financial swaps, (iv) and interest rate swap agreements. These derivative instruments are with five counterparties that are also lenders in the predecessor’s credit facility.

 

Swaps and options are used to manage the predecessor’s exposure to commodity price risk and basis risk inherent in the predecessor’s 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, the predecessor exchanges a stream of payments over time according to specified terms with another counterparty. Specifically for commodity price swap agreements, the predecessor agrees to pay an adjustable or floating price tied to an agreed upon index for the commodity, either natural gas or oil, and in return receives a fixed price based on notional quantities. Under basis swap agreements, the predecessor agrees to pay an adjustable or floating price tied to two agreed upon indices for natural gas and in return receives the differential between a floating index and fixed price based on notional quantities. A collar is a combination of a put purchased by the predecessor and a call option written by the predecessor. In a typical collar transaction, if the floating price based on a market index is below the floor price, the predecessor receives 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, the predecessor 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 the predecessor’s interest rate on amounts borrowed under the credit facility. The purpose of these instruments is to mitigate the predecessor’s existing exposure to unfavorable interest rate changes. Under interest rate swap agreements, the predecessor pays a fixed interest rate payment on a notional amount in exchange for receiving a floating amount based on LIBOR on the same notional amount.

 

The predecessor 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 statements of operations. The predecessor records its derivative activities on a mark-to-market or fair value basis. Fair values are based on pricing models that consider the time value of money and volatility and are comparable to values obtained from counterparties. Pursuant to the accounting standard that permits netting of assets, liabilities, and collateral where the right of offset exists, the predecessor presents the fair value of derivative financial instruments on a net basis.

 

During the second quarter of 2011, the predecessor entered into oil, natural gas and NGL derivative contracts that were contributed to us at the closing of the IPO. These contracts are included in the summary of open derivative positions below. Additionally, in June 2011, the predecessor terminated certain commodity oil swaps totaling approximately 744,800 barrels for a total cost of approximately $11.5 million. These contracts are not included in the summary of open derivative positions below.

 

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At September 30, 2011, the predecessor had the following commodity derivative open positions:

 

 

 

Index

 

2011

 

2012

 

2013

 

2014

 

2015

 

Natural gas positions

 

 

 

 

 

 

 

 

 

 

 

 

 

Price swaps (MMBTUs)

 

NYMEX-HH

 

1,829,762

 

3,684,189

 

6,191,910

 

5,464,908

 

4,902,972

 

Weighted average price

 

 

 

$

6.91

 

$

6.21

 

$

5.56

 

$

5.75

 

$

5.96

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps (MMBTUs)

 

NYMEX-HH

 

1,879,120

 

6,884,475

 

6,077,271

 

 

 

Weighted average price

 

 

 

$

(0.25

)

$

(0.30

)

$

(0.31

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Collars (MMBTUs)

 

NYMEX-HH

 

 

3,375,741

 

 

 

 

Floor-Ceiling price

 

 

 

$

 

$

4.64-7.16

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Positions

 

 

 

 

 

 

 

 

 

 

 

 

 

Price swaps (BBLs)

 

NYMEX-WTI

 

98,430

 

392,785

 

415,718

 

349,524

 

303,888

 

Weighted average price

 

 

 

$

103.23

 

$

102.20

 

$

101.30

 

$

100.01

 

98.90

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Collars (BBLs)

 

NYMEX-WTI

 

20,400

 

 

 

 

 

Floor-Ceiling price

 

 

 

$

120.00-171.50

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL Positions

 

 

 

 

 

 

 

 

 

 

 

 

 

Price swaps (BBLs)

 

NYMEX-WTI

 

64,007

 

217,861

 

 

 

 

Weighted average price

 

 

 

$

52.25

 

$

49.93

 

 

 

 

 

At December 31, 2010, the predecessor had the following commodity derivative open positions:

 

 

 

Index

 

2011

 

2012

 

2013

 

2014

 

Natural gas positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (MMBTUs)

 

NYMEX-HH

 

7,837,761

 

3,684,189

 

2,904,560

 

902,048

 

Weighted average price

 

 

 

$

6.73

 

$

6.21

 

$

5.86

 

$

6.60

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps (MMBTUs)

 

NYMEX-HH

 

8,016,800

 

6,884,480

 

6,077,280

 

 

Weighted average price

 

 

 

$

(0.25

)

$

(0.30

)

$

(0.31

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Collars (MMBTUs)

 

NYMEX-HH

 

3,375,741

 

 

 

 

Floor-Ceiling price

 

 

 

$

4.64-7.16

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (BBLs)

 

NYMEX-WTI

 

325,684

 

267,680

 

256,176

 

220,944

 

Weighted average price

 

 

 

$

103.49

 

$

85.76

 

$

86.77

 

$

87.44

 

 

 

 

 

 

 

 

 

 

 

 

 

Collars (BBLs)

 

NYMEX-WTI

 

81,600

 

 

 

 

Floor-Ceiling price

 

 

 

$

120.00-171.50

 

 

 

 

 

At September 30, 2011, the predecessor had the following interest rate swap contracts:

 

 

 

Notional

 

 

 

 

 

Maturity

 

Amount

 

Average %

 

Index

 

 

 

(in thousands)

 

 

 

 

 

February 2012

 

$

5,231

 

1.180

%

LIBOR

 

November 2012

 

9,500

 

3.300

 

LIBOR

 

February 2013

 

5,135

 

2.205

 

LIBOR

 

February 2013

 

5,135

 

2.260

 

LIBOR

 

 

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At December 31, 2010, the predecessor had the following interest rate swap contracts:

 

 

 

Notional

 

 

 

 

 

Maturity

 

Amount

 

Average %

 

Index

 

 

 

(in thousands)

 

 

 

 

 

May 2011

 

$

2,130

 

3.590

%

LIBOR

 

February 2012

 

5,351

 

1.180

 

LIBOR

 

November 2012

 

9,500

 

3.300

 

LIBOR

 

February 2013

 

5,135

 

2.205

 

LIBOR

 

February 2013

 

5,135

 

2.260

 

LIBOR

 

 

Effect of Derivative Instruments — Balance Sheet

 

The fair value of all commodity and interest rate derivative instruments as of September 30, 2011 is included in the table below:

 

 

 

As of September 30, 2011

 

 

 

Current

 

Long-term

 

Current

 

Long-term

 

 

 

Assets

 

Assets

 

Liabilities

 

Liabilities

 

 

 

(in thousands)

 

Interest rate

 

 

 

 

 

 

 

 

 

Swaps

 

$

 

$

 

$

480

 

$

84

 

Sale of Natural Gas Production

 

 

 

 

 

 

 

 

 

Price swaps

 

11,041

 

11,983

 

 

 

Basis swaps

 

 

 

1,109

 

1,157

 

Collars

 

1,835

 

482

 

 

 

Sale of Crude Oil Production

 

 

 

 

 

 

 

 

 

Price swaps

 

8,764

 

17,716

 

 

 

Collars

 

760

 

 

 

 

Sale of NGLs

 

 

 

 

 

 

 

 

 

Price swaps

 

48

 

146

 

 

 

 

 

$

22,448

 

$

30,327

 

$

1,589

 

$

1,241

 

 

The fair value of all commodity and interest rate derivative instruments as of December 31, 2010 is included in the table below:

 

 

 

As of December 31, 2010

 

 

 

Current

 

Long-term

 

Current

 

Long-term

 

 

 

Assets

 

Assets

 

Liabilities

 

Liabilities

 

 

 

(in thousands)

 

Interest rate

 

 

 

 

 

 

 

 

 

Swaps

 

$

 

$

 

$

594

 

$

267

 

Sale of Natural Gas Production

 

 

 

 

 

 

 

 

 

Price swaps

 

16,929

 

6,590

 

 

 

Basis swaps

 

 

 

379

 

621

 

Collars

 

 

1,177

 

 

161

 

Sale of Crude Oil Production

 

 

 

 

 

 

 

 

 

Price swaps

 

4,694

 

 

1,509

 

4,551

 

Collars

 

2,196

 

 

 

 

 

 

$

23,819

 

$

7,767

 

$

2,482

 

$

5,600

 

 

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Table of Contents

 

Effect of Derivative Instruments — Statement of Operations

 

The unrealized and realized gain or loss amounts and classification related to derivative instruments for the three and nine months ended September 30, 2011 and 2010 are as follows:

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

 

 

September 30,

 

September 30,

 

 

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

 

 

(in thousands)

 

Realized gains (losses):

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Revenue

 

$

6,029

 

$

12,186

 

$

6,070

 

$

35,450

 

Interest rate derivatives

 

Other income (expense)

 

(141

)

(164

)

(439

)

(488

)

Unrealized gains (losses):

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

Revenue

 

29,253

 

(4,542

)

26,144

 

(2,502

)

Interest rate derivatives

 

Other income (expense)

 

134

 

(115

)

297

 

(447

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Credit Risk.   All of the predecessor’s 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.  The predecessor monitors the creditworthiness of each of its counterparties and assesses 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.  The predecessor also has 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 the predecessor.  Additionally, the predecessor considers itself to be of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

 

9.              Related Parties

 

Each of LRR A, LRR B and LRR C has a management agreement with Lime Rock Management, an affiliated entity, to provide management services for the operation and supervision of their respective funds.  The management fee is determined by a formula based on the partners’ invested capital or the equity capital commitment. During the three and nine months ended September 30, 2011, the predecessor paid $1.6 million and $4.5 million, respectively, to Lime Rock Management for management fees.  During the three and nine months ended September 30, 2010, the predecessor paid $1.5 million and $5.3 million, respectively, to Lime Rock Management for management fees.

 

In the normal course of business, certain expenses of the predecessor may be paid by, and subsequently reimbursed to, Lime Rock Management.  At September 30, 2011, $0.2 million was due to Lime Rock Management.  There were no outstanding amounts due to Lime Rock Management at December 31, 2010.

 

In addition, through the normal course of business, certain expenses of the predecessor may be paid by, and subsequently reimbursed to, Lime Rock Resources Operating Company, Inc. (“OpCo”), an affiliated entity, pursuant to a services agreement. As of September 30, 2011 and December 31, 2010, the predecessor had a minimal amount due to or from OpCo.

 

For certain oil and natural gas properties where the predecessor is the operator, the predecessor receives income related to joint interest operations.  For the three and nine months ended September 30, 2011, the predecessor received $0.2 million and $0.8 million, respectively, of income, which reduced the management fee paid by the predecessor to Lime Rock Management.  The predecessor did not record any such amounts during the three or nine months ended September 30, 2010.  All related party transactions are at amounts believed to be commensurate with an arm’s-length transaction between parties and are stated at fair market value.

 

10.       Subsequent Events

 

Subsequent events have been evaluated through December 20, 2011, which is the date the financial statements were made available for issuance.

 

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IPO.  As discussed in Note 1, on November 16, 2011, we completed our IPO of 9,408,000 common units representing limited partner interests in the Partnership at a price to the public of $19.00 per common unit, or $17.8125 per common unit after payment of the underwriting discount.  Total net proceeds from the sale of common units in our IPO were $167.2 million ($178.8 million less $11.2 million for the underwriting discount and a $0.4 million structuring fee).  Estimated IPO costs were approximately $3.9 million.  Approximately $2.6 million of these offering costs are included in our predecessor’s consolidated statement of operations for the nine months ended September 30, 2011.  We expect to reimburse Fund I for all costs related to our IPO.  Net proceeds of the offering, along with $155.8 million of borrowings under our new $500 million senior secured revolving credit agreement, as further discussed below, were utilized to make cash distributions and payments to Fund I of approximately $289.9 million and repay $27.3 million of LRR A’s debt that we assumed at closing.

 

Underwriters’ Option for Additional Units.  On December 14, 2011, we closed the partial exercise of the underwriters’ option to purchase additional units and as a result issued an additional 1,200,000 common units to the public.  The net proceeds from the exercise of the underwriters’ option to purchase additional common units was used to pay additional cash consideration for the properties purchased from Fund I in connection with the IPO and to make additional distributions to Fund I.

 

Acquisition of Common Control Properties.  At the close of the IPO, we entered into a purchase, sale, contribution, conveyance and assumption agreement with Fund I pursuant to which Fund I sold and contributed the Common Control Properties.  Fund I received 6,249,000 common units, 6,720,000 subordinated units and $289.9 million in cash in exchange for the Common Control Properties contributed to the Partnership.

 

Amended and Restated Agreement of Limited Partnership.  On November 16, 2011, in connection with the closing of the IPO, we amended and restated our agreement of limited partnership.  The amended and restated partnership agreement provides, among other things, for registration rights for the benefit of our General Partner and Fund I.

 

Amended and Restated Limited Liability Company Agreement of our General Partner.  In connection with the closing of the IPO, our General Partner also amended and restated its limited liability company agreement.  The amendments to the agreement included provisions regarding, among other things, the issuance of additional classes of membership interests, the rights of the members of the General Partner, distributions and allocations and management by the board of directors of our General Partner.

 

Credit Agreement.  In July 2011, subject to consummation of our IPO, we, as guarantor, and our wholly owned subsidiary, OLLC, as borrower, entered into a five-year, $500 million senior secured revolving credit facility (the “Credit Agreement”) that matures in July 2016.  The Credit Agreement is reserve-based and we are permitted to borrow under our credit facility in an amount up to the borrowing base, which is currently $250 million.  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.  Unanimous approval by the lenders is required for any increase to the borrowing base.  Upon closing of our IPO, we had $155.8 million of indebtedness outstanding under the Credit Agreement.

 

Borrowings under the Credit Agreement are secured by liens on at least 80% of the PV-10 value of our and our subsidiaries’ oil and natural gas properties and all of our equity interests in the OLLC and any future guarantor subsidiaries and all of our and our subsidiaries’ other assets including personal property. Borrowings under the Credit Agreement bear interest, at OLLC’s option, at either (i) the greater of the prime rate as determined by the Administrative Agent, the federal funds effective rate plus 0.50%, and the 30-day adjusted LIBOR plus 1.0%, all of which is subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letter of credit exposure to the borrowing base then in effect), or (ii) the applicable reserve-adjusted LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.

 

The Credit Agreement requires us to maintain a leverage ratio of Total Debt to EBITDAX (as each term is defined in the Credit Agreement) of not more than 4.0 to 1.0, and a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0.

 

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Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our, OLLC’s and any of our subsidiaries’ ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of our production; and prepay certain indebtedness.

 

As noted above, the proceeds from the IPO were partially used to repay $27.3 million of LRR A’s debt. As of December 20, 2011, LRR A has outstanding debt of $4.1 million.

 

In December 2011, our lenders re-affirmed our borrowing base, which is currently $250 million.

 

Services Agreement.  On November 16, 2011, we entered into a services agreement (the “Services Agreement”) by and among Lime Rock Management, OpCo, LRE GP, LLC (the “General Partner”), the Partnership and the OLLC, pursuant to which Lime Rock Management and OpCo will provide certain management, administrative and operating services and personnel to our General Partner and us to manage and operate our business. Under the Services Agreement, our General Partner will reimburse Lime Rock Management and OpCo, on a monthly basis, for the allocable expenses they incur in their performance under the Services Agreement, and we will reimburse our General Partner for such payments it makes to Lime Rock Management and OpCo. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated by Lime Rock Management and OpCo to us. Lime Rock Management and OpCo have discretion to determine in good faith the proper allocation of costs and expenses to our General Partner for their services. Lime Rock Management and OpCo will not be liable to us for their performance of, or failure to perform, services under the Services Agreement unless their acts or omissions constitute gross negligence or willful misconduct.

 

Omnibus Agreement.  On November 16, 2011, we entered into an omnibus agreement (the “Omnibus Agreement”) with our General Partner, OLLC, LRR A, LRR B, LRR C, LRR GP, LLC and Lime Rock Management.  Under the Omnibus Agreement, none of the parties or their respective affiliates have any obligation to offer, or provide any opportunity to pursue, purchase or invest in, any business opportunity to any other party or their affiliates.  The Omnibus Agreement does not restrict any of the parties and their respective affiliates from competing with either Fund I or us, our General Partner, the OLLC and all of their respective subsidiaries.

 

Pursuant to the Omnibus Agreement, each entity of Fund I will indemnify us, our General Partner, the OLLC and their respective subsidiaries against (i) title defects, (ii) income taxes attributable to pre-closing ownership or operation of the contributed assets, including any income tax liabilities related to the formation transactions that occurred on or prior to the closing of the IPO, (iii) environmental claims, losses and expenses associated with the operation of our business prior to the closing of the IPO, subject to a maximum of $10,000,000, (iv) all liabilities, other than liabilities covered under the preceding clause, (iii) relating to the operation of the contributed assets prior to the closing that were not disclosed in the most recent pro forma balance sheet included in our Registration Statement on Form S-1, as amended (File No. 333-174017) or incurred in the ordinary course of business thereafter, and (v) losses resulting from the failure of Fund I to have on the closing date any consent, waiver or governmental permit that renders us, General Partner, the OLLC and their respective subsidiaries unable to own, use or operate the contributed assets in substantially the same manner as they were owned, used or operated immediately prior to the closing of the IPO.

 

Fund I’s indemnification obligation will (i) survive for three years after the closing of the IPO with respect to title defects, (ii) survive for one year after closing with respect to environmental claims, undisclosed liabilities and failure to have any consent, waiver or governmental permits, and (iii) terminate upon the earlier of (y) the expiration of the term of Fund I and (z) sixty days after the expiration of the applicable statute of limitations with respect to income taxes. All claims are subject to a $50,000 per claim de minimus exception, and no claims may be made against Fund I unless such losses exceed $500,000 in the aggregate; thereafter, each entity of Fund I will be liable, severally, in proportion to its contribution percentage, only to the extent that such losses exceed $500,000.

 

Long-Term Incentive Plan.  On November 10, 2011, our General Partner adopted a long-term incentive plan (“2011 LTIP Plan”) for employees, consultants and directors of our General Partner and its affiliates, including Lime Rock Management and OpCo, who perform services for us.  The 2011 LTIP Plan consists of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, unit awards and other unit-based awards.  The 2011 LTIP Plan initially limits the number of units that may be delivered pursuant to vested awards to 1,500,000 common units.  The 2011 LTIP Plan will be administered by our General Partner’s board of directors or a committee thereof.  Our General Partner’s board of directors granted 39,474 restricted units in connection with the closing of our IPO to one of our officers.  These restricted units vest over three years in equal amounts (subject to rounding) on

 

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the anniversary date of the closing of the IPO and will be entitled to receive quarterly distributions during the vesting period.

 

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 statements under “Risk Factors” in our final prospectus (the “Prospectus”) dated November 10, 2011 included in our Registration Statement on Form S-1, as amended (File No. 333-174017), which describe factors that could cause our actual results to differ from those anticipated in the forward-looking statements, including, but not limited to, the following factors:

 

·                  our ability to generate sufficient cash to pay the minimum quarterly distribution 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 oil, natural gas or 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;

·                  general economic conditions;

 

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

·                  the material weakness in our internal control over financial reporting.

 

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”) was formed in April 2011 by Lime Rock Management LP (“Lime Rock Management”), an affiliate of Fund I (defined below), to operate, acquire, exploit and develop producing oil and natural gas properties in North America with long-lived, predictable production profiles.  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”) 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” or “predecessor” refer collectively to LRR A, LRR B and LRR C.  Fund I’s underlying properties consist of working interests in certain oil and natural gas properties owned by LRR A located in New Mexico, Oklahoma and Texas and related net profits interests in these same oil and natural gas properties owned by LRR B and LRR C.  Fund I is managed by Lime Rock Management and pays a management fee to Lime Rock Management.  In addition, Fund I also received administrative services from Lime Rock Resources Operating Company, Inc (“OpCo”).

 

In connection with the completion of our initial public offering (“IPO”) on November 16, 2011, pursuant to a contribution, conveyance and assumption agreement, we acquired specified oil and natural gas properties and related net profits interests and operations and certain commodity derivative contracts covering approximately 85% of our estimated production from total proved developed producing reserves for each of the years ending December 31, 2011 through 2015 based on production estimates in our reserve reports as of March 31, 2011 (the “Common Control Properties”) owned by LRR A, LRR B, and LRR C.  As consideration for the Common Control Properties, Fund I received 6,249,600 common units, 6,720,000 subordinated units, $289.9 million in cash and the assumption of $27.3 million of LRR A’s indebtedness.  For further discussion regarding our IPO, please see Notes 1 and 10 to the unaudited combined condensed financial statements included in this quarterly report.

 

The following discussion analyzes the financial condition and results of operations of Fund I.  Such analysis should be read in conjunction with Fund I’s historical audited combined financial statements, and the notes thereto, included in the final prospectus dated November 10, 2011 (the “Prospectus”) included in our Registration Statement on Form S-1, as amended (SEC File No. 333-174017).

 

Results of Operations

 

The table below summarizes certain of the results of operations attributable to our predecessor for the periods indicated.  Because the results of our predecessor include results for both the properties conveyed to us in connection with our IPO and properties retained by our predecessor, we do not consider these results of our predecessor to be indicative of our future results.

 

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Three Months

 

Nine Months

 

 

 

Ended September 30,

 

Ended September 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

Revenues (in thousands):

 

 

 

 

 

 

 

 

 

Oil sales

 

$

16,677

 

$

13,573

 

$

51,338

 

$

39,542

 

Natural gas sales

 

9,699

 

12,330

 

31,453

 

37,516

 

Natural gas liquids sales

 

4,508

 

3,057

 

12,266

 

10,488

 

Realized gain (loss) on commodity derivative instruments

 

6,029

 

12,186

 

6,070

 

35,450

 

Unrealized gain (loss) on commodity derivative instruments

 

29,253

 

(4,542

)

26,144

 

(2,502

)

Other income

 

42

 

31

 

122

 

77

 

Total revenues

 

$

66,208

 

$

36,635

 

$

127,393

 

$

120,571

 

 

 

 

 

 

 

 

 

 

 

Expenses (in thousands):

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

6,797

 

$

4,917

 

$

18,732

 

$

15,360

 

Production and ad valorem taxes

 

2,711

 

1,822

 

5,731

 

6,889

 

Depletion and depreciation

 

11,163

 

16,102

 

32,034

 

45,686

 

Impairment of oil and natural gas properties

 

16,765

 

 

16,765

 

10,944

 

Accretion expense

 

368

 

343

 

1,112

 

1,012

 

(Gain) loss on settlement of asset retirement obligations

 

39

 

 

39

 

 

Management fees

 

1,579

 

1,534

 

4,546

 

5,337

 

General and administrative expenses

 

1,208

 

659

 

4,414

 

4,331

 

Interest expense

 

(255

)

(281

)

(814

)

(1,009

)

Realized loss on interest rate derivative instruments

 

(141

)

(164

)

(439

)

(488

)

 

 

 

 

 

 

 

 

 

 

Production:

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

192

 

190

 

563

 

536

 

Natural gas (MMcf)

 

2,262

 

2,958

 

7,464

 

8,490

 

NGLs (MBbls)

 

83

 

92

 

237

 

275

 

Total (MBoe)

 

652

 

775

 

2,044

 

2,226

 

Average net production (Boe/d)

 

7,087

 

8,424

 

7,487

 

8,154

 

 

 

 

 

 

 

 

 

 

 

Average sales price:

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

 

 

 

 

 

 

 

 

Sales price

 

$

86.86

 

$

71.44

 

$

91.19

 

$

73.77

 

Effect of realized commodity derivative instruments

 

10.31

 

23.21

 

(13.90

)

24.13

 

Realized price

 

$

97.17

 

$

94.65

 

$

77.29

 

$

97.90

 

Natural gas (per Mcf)

 

 

 

 

 

 

 

 

 

Sales price

 

$

4.29

 

$

4.17

 

$

4.21

 

$

4.42

 

Effect of realized commodity derivative instruments

 

1.79

 

2.63

 

1.86

 

2.65

 

Realized price

 

$

6.08

 

$

6.80

 

$

6.07

 

$

7.07

 

NGLs (per Bbl)

 

$

54.31

 

$

33.23

 

$

51.76

 

$

38.14

 

 

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Three Months

 

Nine Months

 

 

 

Ended September 30,

 

Ended September 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

Average unit cost per Boe:

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

10.42

 

$

6.34

 

$

9.16

 

$

6.90

 

Production and ad valorem taxes

 

$

4.16

 

$

2.35

 

$

2.80

 

$

3.09

 

Depletion and depreciation

 

$

17.12

 

$

20.78

 

$

15.67

 

$

20.52

 

Management fees

 

$

2.42

 

$

1.98

 

$

2.22

 

$

2.40

 

General and administrative expenses

 

$

1.85

 

$

0.85

 

$

2.16

 

$

1.95

 

 

Factors Affecting the Comparability of the Historical Financial Results of Our Predecessor

 

The comparability of our predecessor’s results of operations among the periods presented is impacted by:

·                  The following acquisitions by our predecessor:

·                  the Potato Hill acquisition for a purchase price of approximately $104.0 million in February 2010;

·                  the acquisition of interests in 30 producing oil and natural gas wells located in Texas for a purchase price of approximately $7.5 million in August 2010;

·                  the acquisition of additional interests in producing oil and natural gas wells located in New Mexico for a purchase price of approximately $1.8 million in October 2010; and

·                  The following divestitures by our predecessor:

·                  the divestiture of interests in 17 producing oil and natural gas wells located in New Mexico for approximately $14.3 million in October 2010; and

·                  the divestiture of interests in producing oil and natural gas wells located in New Mexico for approximately $2.9 million in May 2011.

 

Three Months Ended September 30, 2011 Compared to the Three Months Ended September 30, 2010

 

Our predecessor recorded net income of approximately $25.6 million for the three months ended September 30, 2011 compared to net income of $10.6 million for the three months ended September 30, 2010.  This increase in net income was primarily driven by an increase in total revenues, as described below, including an increase in gains on derivative instruments.  This increase in revenues was partially offset by an impairment charge recorded in the third quarter of 2011.

 

Sales Revenues. Revenues from oil, NGLs and natural gas sales for the three months ended September 30, 2011 were $30.9 million as compared to $29.0 million for the three months ended September 30, 2010.  The increase in revenues was due to an increase in the sale of oil of $16.7 million for the three months ended September 30, 2011 as compared to $13.6 million for the three months ended September 30, 2010.  Revenues from the sale of natural gas declined from $12.3 million in the three months ended September 30, 2010 to $9.7 million for the three months ended September 30, 2011.  Revenues from the sale of NGLs were $4.5 million for the three months ended September 30, 2011 compared to $3.1 million of revenues for the three months ended September 30, 2010.  The overall increase in revenues was primarily driven by increases in commodity prices offset by declines in production from natural gas and NGLs.

 

Our predecessor’s production volumes for the three months ended September 30, 2011 included 275 MBbls of oil and NGLs and 2,262 MMcf of natural gas, or 2,989 Bbl/d of oil and NGLs and 24,587 Mcf/d of natural gas.  On an equivalent net basis, production for the three months ended September 30, 2011 was 652 MBoe, or 7,087 Boe/d.  In comparison, our predecessor’s production volumes for the three months ended September 30, 2010 included 282 MBbls of oil and NGLs and 2,958 MMcf of natural gas, or 3,065 Bbl/d of oil and NGLs and 32,152 Mcf/d of natural gas.  On an equivalent net basis, production for the three months ended September 30, 2010 was 775 MBoe, or 8,424 Boe/d.  The declines in natural gas production were primarily driven by a production curtailment at our predecessor’s Pecos Slope field and production declines at our predecessor’s Potato Hills fields.

 

Since late April 2011, approximately 2 MMcf/d of our predecessor’s Pecos Slope field production has been curtailed due to the gas containing a nitrogen percentage greater than our predecessor’s gas purchaser’s

 

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specification.  Our predecessor is actively working with its gas gatherer to reduce the nitrogen percentage to a level within specification.  Our predecessor resumed production of approximately 30% of the curtailed production at the end of the third quarter of 2011 when a nitrogen rejection (membrane) unit was installed.  Full restoration of production is currently expected to occur during the second quarter of 2012 after a field-wide nitrogen rejection facility is installed by the gas gathering company.  The actual timing and amount of resumed production may differ from these estimates.

 

Our predecessor’s average sales price per Bbl for oil and NGLs, excluding commodity derivative contracts, for the three months ended September 30, 2011 was $86.86 and $54.31, respectively, compared with $71.44 and $33.23, respectively, for the three months ended September 30, 2010.  Similarly, our predecessor’s average sales price per Mcf of natural gas, excluding commodity derivative contracts, for the three months ended September 30, 2011 was $4.29 compared with $4.17 per Mcf for the comparable period in 2010.

 

Effects of Commodity Derivative Contracts. Due to fluctuations in oil and natural gas prices, our predecessor recorded a net gain from its commodity hedging program for the three months ended September 30, 2011 of approximately $35.3 million, consisting of a realized gain of approximately $6.0 million and an unrealized gain of approximately $29.3 million.  For the three months ended September 30, 2010, our predecessor recorded a net gain from its commodity hedging program of approximately $7.7 million, consisting of a realized gain of approximately $12.2 million and an unrealized loss of approximately $4.5 million.

 

Lease Operating Expenses. Our predecessor’s lease operating expenses were approximately $6.8 million for the three months ended September 30, 2011 compared to $4.9 million for the three months ended September 30, 2010.  The increase in lease operating expenses was primarily a result of approximately $0.9 million of additional expenses at our predecessor’s Coral Canyon field primarily related to increased saltwater disposal costs and repairs and maintenance expense.  Our predecessor invested capital in the third quarter of 2011 to help reduce future saltwater disposal costs.  The remaining increase was related to additional lease operating expenses associated with our predecessor’s Red Lake field of approximately $0.9 million, primarily a result of higher repairs and maintenance expense and new wells coming online.  On a per Boe basis, our predecessor’s unit lease operating expenses increased to $10.42 per Boe produced for the three months ended September 30, 2011 from approximately $6.34 per Boe produced in the three months ended September 30, 2010.

 

Production and Ad Valorem Taxes. Production and ad valorem taxes increased to approximately $2.7 million for the three months ended September 30, 2011 compared to approximately $1.8 million for the three months ended September 30, 2010 primarily due to a $0.7 million severance tax refund received in the third quarter of 2010.  On a per Boe basis, production and ad valorem taxes increased to $4.16 per Boe for the three months ended September 30, 2011 as compared to $2.35 per Boe for the three months ended September 30, 2010.

 

Depletion and Depreciation. Our predecessor’s depletion and depreciation expenses were approximately $11.2 million, or $17.12 per Boe, for the three months ended September 30, 2011 compared to $16.1 million, or $20.78 per Boe, for the three months ended September 30, 2010.  The overall decrease was primarily a result of the impairment charges recorded and an increase in reserves during 2011.

 

Impairment of Oil and Natural Gas Properties.  Our predecessor recorded an impairment charge of $16.8 million during the three months ended September 30, 2011 due to a decline in commodity prices in the third quarter of 2011.  No impairment charge was recorded during the three months ended September 30, 2010.  If expected future oil and natural gas prices decline or we experience a loss of reserves during the last quarter of 2011 or future periods, the estimated undiscounted future cash flows for the proved oil and natural gas properties may not exceed the net capitalized costs for the predecessor’s properties and a non-cash impairment charge may be required to be recognized in future periods.

 

Management Fees. Our predecessor incurs a management fee paid to Lime Rock Management in addition to the direct general and administrative expenses it incurs.  The management fee is determined by a formula based on the predecessor’s limited partners’ invested capital or the equity capital commitment in Fund I.  Our predecessor’s management fees were approximately $1.6 million for the three months ended September 30, 2011 compared to approximately $1.5 million for the three months ended September 30, 2010.

 

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General and Administrative Expenses. Our predecessor’s general and administrative expenses were approximately $1.2 million for the three months ended September 30, 2011 compared to $0.7 million for the three months ended September 30, 2010.  The increase was primarily driven by transaction costs associated with our IPO.  General and administrative costs per Boe were $1.85 for the three months ended September 30, 2011 and $0.85 per Boe produced for the three months ended September 30, 2010.

 

Interest Expense. Our predecessor’s interest expense is comprised of interest on its credit facility, debt issuance costs and realized gains (losses) on its interest rate derivative instruments.  The interest expense was $0.4 million for the three months ended September 30, 2011 and 2010.

 

Nine Months Ended September 30, 2011 Compared to the Nine Months Ended September 30, 2010

 

Our predecessor recorded net income of approximately $43.2 million for the nine months ended September 30, 2011 compared to net income of $29.1 million for the nine months ended September 30, 2010.  This increase in net income was primarily driven by an increase in total revenues, as described below, in addition to a decrease in total operating costs.

 

Sales Revenues. Revenues from oil, NGLs and natural gas sales for the nine months ended September 30, 2011 were $95.1 million as compared to $87.5 million for the nine months ended September 30, 2010.  The increase in revenues was due to an increase in the sale of oil of $51.3 million for the nine months ended September 30, 2011 as compared to $39.5 million for the nine months ended September 30, 2010.  Revenues from the sale of natural gas declined from $37.5 million in the nine months ended September 30, 2010 to $31.5 million for the nine months ended September 30, 2011.  Revenues from the sale of NGLs of $12.3 million for the nine months ended September 30, 2011 were higher than the $10.5 million of revenues for the nine months ended September 30, 2010.  The overall increase in revenues was primarily driven by increases in oil commodity prices offset by declines in natural gas commodity prices and production from the previous period.

 

Our predecessor’s production volumes for the nine months ended September 30, 2011 included 800 MBbls of oil and NGLs and 7,464 MMcf of natural gas, or 2,930 Bbl/d of oil and NGLs and 27,341 Mcf/d of natural gas.  On an equivalent net basis, production for the nine months ended September 30, 2011 was 2,044 MBoe, or 7,487 Boe/d.  In comparison, our predecessor’s production volumes for the nine months ended September 30, 2010 included 811 MBbls of oil and NGLs and 8,490 MMcf of natural gas, or 2,971 Bbl/d of oil and NGLs and 31,099 Mcf/d of natural gas.  On an equivalent net basis, production for the nine months ended September 30, 2010 was 2,226 MBoe, or 8,154 Boe/d.  The declines in natural gas production were primarily driven by a production curtailment at our predecessor’s Pecos Slope field, production declines at our predecessor’s New Years Ridge fields and the impact of the September 2010 divestiture mentioned above.

 

Since late April 2011, approximately 2 MMcf/d of our predecessor’s Pecos Slope field production has been curtailed due to the gas containing a nitrogen percentage greater than our predecessor’s gas purchaser’s specification.  Our predecessor is actively working with its gas gatherer to reduce the nitrogen percentage to a level within specification.  Our predecessor resumed production of approximately 30% of the curtailed production at the end of the third quarter of 2011 when a nitrogen rejection (membrane) unit was installed.  Full restoration of production is currently expected to occur during the second quarter of 2012 after a field-wide nitrogen rejection facility is installed by the gas gathering company.  The actual timing and amount of resumed production may differ from these estimates.

 

Our predecessor’s average sales price per Bbl for oil and NGLs, excluding commodity derivative contracts, for the nine months ended September 30, 2011 was $91.19 and $51.76, respectively, compared with $73.77 and $38.14, respectively, for the nine months ended September 30, 2010.  Similarly, our predecessor’s average sales price per Mcf of natural gas, excluding commodity derivative contracts, for the nine months ended September 30, 2011 was $4.21 compared with $4.42 per Mcf for the comparable period in 2010.

 

Effects of Commodity Derivative Contracts. Due to fluctuations in oil and natural gas prices, our predecessor recorded a net gain from its commodity hedging program for the nine months ended September 30, 2011 of approximately $32.2 million, which is composed of a realized gain of approximately $6.1 million and an unrealized gain of approximately $26.1 million.  For the nine months ended September 30, 2010, our predecessor recorded a

 

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net gain from its commodity hedging program of approximately $32.9 million, consisting of a realized gain of approximately $35.4 million offset by an unrealized loss of approximately $2.5 million.

 

Lease Operating Expenses. Our predecessor’s lease operating expenses were approximately $18.7 million for the nine months ended September 30, 2011 compared to $15.4 million for the nine months ended September 30, 2010.  The increase in lease operating expenses was a result of approximately $3.2 million of additional expenses at our predecessor’s Red Lake field, primarily related to new wells coming online as well as increased saltwater disposal costs and repairs and maintenance expenses.  Lease operating expenses at our predecessor’s Coral Canyon field also increased approximately $0.8 million due to increased saltwater disposal costs and additional repairs and maintenance expense.  Our predecessor invested capital during the third quarter of 2011 to help reduce future saltwater disposal costs.  These increases were offset by lower workover expenses of approximately $0.7 million.  On a per Boe basis, our predecessor’s unit lease operating expenses increased to $9.16 per Boe produced for the nine months ended September 30, 2011 from approximately $6.90 per Boe produced in the nine months ended September 30, 2010.

 

Production and Ad Valorem Taxes. Production and ad valorem taxes decreased to approximately $5.7 million for the nine months ended September 30, 2011 compared to approximately $6.9 million for the nine months ended September 30, 2010 primarily due to changes in the estimates of the appraisals on which our predecessor’s property taxes were calculated.  On a per Boe basis, production and ad valorem taxes decreased to $2.80 per Boe for the nine months ended September 30, 2011 compared to $3.09 per Boe for the nine months ended September 30, 2010.

 

Depletion and Depreciation. Our predecessor’s depletion and depreciation expenses were approximately $32.0 million, or $15.67 per Boe, for the nine months ended September 30, 2011 compared to $45.7 million, or $20.52 per Boe, for the nine months ended September 30, 2010.  The overall decrease was primarily a result of the impairment charges recorded as well as an increase in reserves in 2011.

 

Impairment of Oil and Natural Gas Properties. Our predecessor recorded an impairment charge of $16.8 million and $10.9 million, respectively, during the nine months ended September 30, 2011 and 2010, respectively, due to declines in commodity prices during the respective periods.  If expected future oil and natural gas prices decline or we experience a loss of reserves during the last quarter of 2011 or future periods, the estimated undiscounted future cash flows for the proved oil and natural gas properties may not exceed the net capitalized costs for the predecessor’s properties and a non-cash impairment charge may be required to be recognized in future periods.

 

Management Fees. Our predecessor incurs a management fee paid to Lime Rock Management in addition to the direct general and administrative expenses it incurs.  The management fee is determined by a formula based on the predecessor’s limited partners’ invested capital or the equity capital commitment in Fund I.  Our predecessor’s management fees were approximately $4.5 million for the nine months ended September 30, 2011 compared to approximately $5.3 million for the nine months ended September 30, 2010.  The overall decrease of $0.8 million was primarily a result of changing the formula based on equity capital commitments to invested capital due to meeting certain requirements as outlined in our predecessor’s partnership agreements with its limited partners.

 

General and Administrative Expenses. Our predecessor’s general and administrative expenses were approximately $4.4 million for the nine months ended September 30, 2011 compared to $4.3 million for the nine months ended September 30, 2010.  These amounts include a $2.5 million finder’s fee incurred in connection with the Potato Hills acquisition in 2010, offset by $2.6 million in transaction costs associated with our initial public offering.  The general and administrative costs per Boe were $2.16 for the nine months ended September 30, 2011 and $1.95 per Boe produced for the nine months ended September 30, 2010.

 

Interest Expense. Our predecessor’s interest expense is comprised of interest on its credit facility, debt issuance costs and realized gains (losses) on its interest rate derivative instruments.  The interest expense was $1.3 million for the nine months ended September 30, 2011 compared to $1.5 million for the nine months ended September 30, 2010.

 

Liquidity and Capital Resources

 

Our predecessor’s primary sources of capital and liquidity have been proceeds from capital contributions from

 

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the partners of its limited partnerships, bank borrowings, and cash flow from operations.  To date, our predecessor’s primary use of capital has been for the acquisition of oil and natural gas properties.

 

Bank borrowings were approximately $27.3 million at September 30, 2011 and December 31, 2010.  Such indebtedness during those periods was used primarily to fund acquisitions of oil and natural gas properties.

 

Predecessor Cash Flows

 

Operating.  Our predecessor’s net cash provided by operating activities was approximately $70.2 million and $90.8 million for the nine month periods ended September 30, 2011 and 2010, respectively.  The decrease was primarily driven by the changes in commodity prices over the respective periods.  Cash provided by operating activities is impacted by the prices received for oil and natural gas sales and levels of production volumes.  Our predecessor’s production volumes in the future will in large part be dependent upon the dollar amount and results of future capital expenditures.  Future levels of capital expenditures made by our predecessor may vary due to many factors, including drilling results, oil and natural gas prices, industry conditions, the prices and availability of goods and services and the extent to which proved properties are acquired.

 

Our predecessor’s working capital totaled $24.5 million and $33.2 million at September 30, 2011 and December 31, 2010, respectively.  Our predecessor’s collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant.  Our predecessor’s cash balances totaled $5.7 million and $12.5 million at September 30, 2011 and December 31, 2010, respectively.

 

Investing.  Net cash used in investing activities by our predecessor was approximately $39.7 million and $128.0 million for the nine month periods ended September 30, 2011 and 2010, respectively.  The amount of cash used in investing activities during the nine months ended September 30, 2010 was principally for the acquisitions of oil and gas properties.  There were no material acquisitions of oil and gas properties in 2011.

 

Financing.  Net cash used in financing activities by our predecessor was approximately $37.2 million in the nine months ended September 30, 2011 compared to net cash provided by financing activities of approximately $39.4 million in the nine months ended September 30, 2010.  For the nine months ended September 30, 2011, our predecessor made distributions of approximately $42.6 million and received capital contributions of approximately $5.4 million.  For the nine months ended September 30, 2010, our predecessor received capital contributions of approximately $125.5 million and borrowed approximately $3.7 million.  These amounts were offset by distributions of approximately $80.5 million and capital contributions returned of approximately $9.3 million.  The increased activity during 2010 was primarily driven by the Potato Hills acquisition in the beginning of the year.

 

Derivative Contracts

 

The following table summarizes, for the periods presented, the weighted average price and notional volumes of our predecessor’s oil, NGL and natural gas swaps and collars in place as of September 30, 2011. 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. Our predecessor uses swaps and collars as a mechanism for managing commodity price risks whereby it pays the counterparty floating prices and receives fixed prices from the counterparty. By entering into the hedge agreements, our predecessor mitigates the effect on its cash flows of changes in the prices it receives for its oil and natural gas production. These transactions are settled based upon the NYMEX-WTI price of oil and NYMEX-Henry Hub price of natural gas on the average of the three final trading days of the month, with settlement occurring on the fifth day of the production month.

 

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Table of Contents

 

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

Oil (NYMEX-WTI)

 

NGL (NYMEX-WTI)

 

(NYMEX-Henry Hub)

 

 

 

Weighted Average

 

Weighted Average

 

Weighted Average

 

Term

 

$/Bbl

 

Bbls/d

 

$/Bbl

 

Bbls/d

 

$/Mmbtu

 

Mmbtu/d

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2011

 

$

106.11

 

1,292

 

$

52.25

 

696

 

$

6.91

 

19,889

 

2012

 

$

102.20

 

1,076

 

$

49.93

 

597

 

$

5.46

 

19,342

 

2013

 

$

101.30

 

1,139

 

$

 

 

$

5.56

 

16,964

 

2014

 

$

100.01

 

958

 

$

 

 

$

5.75

 

14,972

 

2015

 

$

98.90

 

833

 

$

 

 

$

5.96

 

13,433

 

 

The following table summarizes, for the periods presented, our predecessor’s oil and natural gas basis swaps in place as of September 30, 2011. These contracts are designed to effectively fix a price differential between 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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2011

 

$

(0.34

)

8,237

 

$

(0.12

)

5,017

 

$

(0.26

)

5,808

 

$

(0.21

)

1,363

 

2012

 

$

(0.38

)

7.763

 

$

(0.15

)

4,391

 

$

(0.31

)

5,434

 

$

(0.25

)

1,273

 

2013

 

$

(0.39

)

7,025

 

$

(0.16

)

3,608

 

$

(0.32

)

4,874

 

$

(0.27

)

1,143

 

 

Predecessor Credit Facility

 

LRR A’s $45.0 million credit facility, entered into on November 23, 2010, has an aggregate maximum commitment of $45.0 million and an aggregate current borrowing base of $31.5 million as of September 30, 2011. The credit facility is secured by mortgages on substantially all of LRR A’s oil and natural gas properties, including the properties contributed to us by our predecessor in connection with the closing of our IPO in November 2011. In connection with the IPO closing, the credit facility was amended to permit the contribution of these properties to us.

 

The borrowing base is subject to review and adjustment on a semiannual basis and other interim adjustments as requested by the lenders, as applicable. At the election of LRR A, amounts outstanding under the credit facility bear interest at specified margins over LIBOR of 2.00% to 2.75% or specified margins over an Alternate Base Rate of 1.00% to 1.75%. The Alternate Base Rate is the greater of the Prime Rate, the Fed Funds Rate plus 1/2 of 1%, or the adjusted LIBOR for a one-month Interest Period plus 1%. Such margins will fluctuate based on the utilization of the credit facility.

 

As of September 30, 2011, the interest rate on LRR A’s credit facility, taking into account LRR A’s interest rate swaps, was an average of 4.75%. LRR A’s borrowings under the credit facility totaled $27.3 million at September 30, 2011.  In connection with the closing of our IPO in November 2011, we assumed and repaid this debt with borrowings under our credit facility.

 

LRR A’s credit facility contains financial and other covenants, including a current ratio test and an interest coverage test. Except for the current ratio covenant, LRR A was in compliance with all covenants under the credit facility at September 30, 2011.  LRR A received a waiver for non-compliance with this covenant.

 

Predecessor Contractual Obligations

 

There have been no material changes to our predecessor’s contractual obligations from those described in our Prospectus.

 

Off Balance Sheet Arrangements

 

As of September 30, 2011, our predecessor had no off-balance sheet arrangements.

 

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Critical Accounting Policies and Estimates

 

There have been no material changes to our predecessor’s critical accounting policies from those described in our Prospectus.

 

Recently Issued Accounting Pronouncements

 

We do not expect the adoption of any accounting standards in 2011 to have a material impact to our or our predecessor’s financial statements.

 

Supplemental Disclosures Regarding LRR Energy, L.P.

 

As noted above, the results discussed above included combined results for both the properties conveyed to us in connection with our IPO and properties retained by our predecessor. The following table provides selected results for only the properties conveyed to us in connection with our IPO. The following information is for informational purposes only and should not be considered indicative of future results.

 

 

 

Three Months

 

Nine Months

 

 

 

Ended September 30,

 

Ended September 30,

 

 

 

2011

 

2010

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

Production:

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

118

 

113

 

338

 

315

 

Natural gas (MMcf)

 

1,999

 

2,681

 

6,666

 

7,561

 

NGLs (MBbls)

 

63

 

72

 

175

 

201

 

Total (MBoe)

 

514

 

632

 

1,624

 

1,776

 

Average net production (Boe/d)

 

5,587

 

6,870

 

5,949

 

6,505

 

 

 

 

 

 

 

 

 

 

 

Revenues (in thousands):

 

 

 

 

 

 

 

 

 

Oil

 

$

10,161

 

$

8,025

 

$

30,332

 

$

23,119

 

Natural gas

 

8,476

 

11,119

 

27,928

 

33,266

 

NGLs

 

3,518

 

2,422

 

9,246

 

7,658

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses (in thousands)

 

$

4,865

 

$

4,043

 

$

14,166

 

$

12,641

 

 

 

 

 

 

 

 

 

 

 

Production and ad valorem taxes (in thousands)

 

$

2,131

 

$

1,968

 

$

3,763

 

$

5,919

 

 

With the exception of natural gas, production from the Common Control Properties remained relatively consistent for the periods presented.  Production from natural gas was down for the three and nine months ended September 30, 2011 as compared to the same periods in 2010 due to the production curtailment at Pecos Slope and declines in the Potato Hills and New Years Ridge fields as mentioned above.  Revenues from the sale of oil and NGLs were higher in 2011 primarily due to higher commodity prices.  Revenues from the sale of natural gas were generally lower in 2011 due to lower natural gas prices and lower production.

 

Lease operating expenses related to the Common Control Properties were higher in 2011 as compared to 2010 primarily due to increased salt water disposal costs and higher repairs and maintenance expenses.  Our predecessor invested capital during the third quarter of 2011 to help reduce our future saltwater disposal costs.  Production and ad valorem taxes for the three months ended September 30, 2011 were consistent with the comparable period of 2010.  Production and ad valorem taxes for the nine months ended September 30, 2011 were lower than the comparable period of 2010 primarily due to changes in the estimates of the appraisals on which our property taxes were calculated.

 

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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 the Prospectus under the caption “Management’s Discussion and Analysis or Financial Condition and Results of Operations — Predecessor Quantitative and Qualitative Disclosure About Market Risk.”

 

Item 4.  Controls and Procedures.

 

Material Weakness in Internal Control over Financial Reporting and Status of Remediation Efforts.  As previously disclosed in our Prospectus, prior to the completion of our IPO in November 2011, our predecessor was a private entity with limited accounting personnel and other supervisory resources to adequately execute its accounting processes and address its internal control over financial reporting.  Our predecessor’s lack of adequate staffing levels contributed to several audit adjustments to the financial statements for the year ended December 31, 2010.  In connection with the audit of our predecessor’s financial statements for the year ended December 31, 2010, our predecessor’s independent registered accounting firm identified and communicated material weaknesses related to maintaining an effective control environment in that the design and execution of controls have not consistently resulted in effective review and supervision by individuals with financial reporting oversight roles given the lack of adequate staffing levels.  Additionally, our predecessor did not maintain effective controls over the completeness and accuracy of key spreadsheets used in its computations of various estimates, including depletion and asset retirement obligations.  Effective controls were not adequately designed or consistently operated to ensure that key computations were capturing the appropriate information completely and accurately before closing adjustments were made to our predecessor’s accounting records.  The lack of adequate staffing levels and lack of effective controls over the completeness and accuracy of key spreadsheets resulted in insufficient time spent on review and approval of certain information used to prepare our predecessor’s financial statements, resulting in several audit adjustments to our predecessor’s financial statements for the year ended December 31, 2010.

 

Prior to the completion of the audit for the year ended December 31, 2010, our predecessor began to implement new accounting processes and control procedures and also hired additional personnel.  Further, to address these material weaknesses, starting in early 2011, our predecessor hired additional accounting and financial reporting staff, implemented additional analysis and reconciliation procedures and increased the levels of review and approval.  Additionally, we have begun taking steps to comprehensively document and analyze our system of internal controls over financial reporting.  Due to the recent implementation of these changes to the control environment which have not yet been subject to a year-end audit, management continues to evaluate the design and effectiveness of these control changes in conjunction with its ongoing evaluation, review and formalization of internal controls during the remainder of 2011 and in connection with the year-end review process.

 

Evaluation of Disclosure Controls and Procedures.  As required by Rule 13a-15(b) of the Securities Exchange Act, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officers and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report.  Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file 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.  In light of the material weaknesses with respect to the year ended December 31, 2010 identified above, and although we have implemented significant changes to our internal control structure as noted above, we have not had the opportunity to test these controls; therefore, our principal executive officers and principal financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of September 30, 2011.  Notwithstanding the identified material weaknesses with respect to the year ended December 31, 2010, management concluded that the financial statements and other financial information in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 presents fairly in all material respects the financial condition, results of operations and cash flows for all periods presented.

 

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Changes in Internal Control over Financial Reporting.  As described above, there were changes in our predecessor’s system of internal controls over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the quarter ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, our predecessor’s internal controls over financial reporting.

 

In addition, in connection with the IPO in November 2011, we adopted certain governance policies in order to strengthen our corporate governance and comply with the requirements of the New York Stock Exchange.  These changes included the appointment of three independent members of the Board of Directors, the establishment of Governance Guidelines, the establishment of an Audit Committee and the adoption of an Audit Committee Charter and the adoption of a Code of Business Conduct and Ethics.

 

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 or predecessor 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 predecessor, or contemplated to be brought against us or our general partner or predecessor, under the various environmental protection statues to which we or they are subject.

 

Item 1A.  Risk Factors.

 

There have been no material changes to the risk factors described in our Prospectus.

 

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

 

There were no sales of unregistered equity securities during the quarter ended September 30, 2011.

 

On November 10, 2011, we commenced our IPO pursuant to our Registration Statement on Form S-1 (File No. 333-174017), which was declared effective by the SEC on November 10, 2011.  Wells Fargo Securities, LLC, Raymond James & Associates, Inc., Citigroup Global Markets Inc. and RBC Capital Markets, LLC served as the joint-book running managers for the offering.

 

Upon the closing of our IPO on November 16, 2011, we issued 9,408,000 common units pursuant to the Registration Statement at a price to the public of $19.00 per common unit.  The Registration Statement registered common units (including over-allotment common units) with a maximum aggregate offering price of $205.6 million. The gross aggregate offering amount of the securities sold pursuant to the Registration Statement was $178.8 million. In connection with our IPO, we granted the underwriters a 30-day option to purchase up to an additional 1,411,200 common units on the same terms and conditions as set forth in the Prospectus.

 

Net proceeds from the sale of the common units were approximately $167.2 million, after deducting the underwriting discount of approximately $11.2 million and a structuring fee of $0.4 million. Together with borrowings of approximately $155.8 million under our new revolving credit facility, we used the net proceeds to make cash distributions and payments to Fund I of approximately $289.9 million; repay in full $27.3 million of LRR A’s debt that we assumed at the closing of the IPO; pay estimated fees and expenses of approximately $1.9 million relating to our new credit facility; and pay estimated offering expenses of approximately $3.9 million.

 

At the closing of our IPO, we also issued 6,249,600 unregistered common units and 6,720,000 unregistered subordinated units to Fund I as partial consideration for the Common Control Properties.

 

On December 14, 2011, we closed the partial exercise of the underwriters’ option to purchase additional units and as a result issued an additional 1,200,000 common units to the public.  The net proceeds from the exercise of the underwriters’ option to purchase additional common units was used to pay additional cash consideration for the properties purchased from Fund I in connection with the IPO and to make additional distributions to Fund I.

 

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Item 3.  Defaults Upon Senior Securities.

 

None.

 

Item 4.  (Removed and Reserved).

 

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 3.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on November 22, 2011).

 

 

 

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*

 

Stakeholders’ Agreement, dated effective as of May 5, 2011, by and among LRR Energy, L.P., LRE GP, LLC, Lime Rock Resources GP, L.P., Lime Rock Resources A, L.P., Lime Rock Resources B, L.P., Lime Rock Resources C, L.P., Lime Rock Management LP, Lime Rock Resources GP II, L.P., Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P. (incorporated by reference to Exhibit 10.7 to the Partnership’s Registration Statement on Form S-1 (Registration No. 333-174017) filed on May 6, 2011).

 

 

 

10.2*

 

Credit Agreement, dated as of July 22, 2011, among LRE Operating, LLC, as Borrower, LRR Energy, L.P., as Parent Guarantor, the lenders from time to time party thereto, Wells Fargo Bank, National Association, as Administrative Agent, Bank of America, N.A., as Syndication Agent, and BNP Paribas, Citibank, N.A. and Royal Bank of Canada, as Co-Documentation Agents (incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on November 22, 2011).

 

 

 

10.3*

 

First Amendment to Credit Agreement, dated as of September 30, 2011, among LRE Operating, LLC, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.4 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on November 22, 2011).

 

 

 

10.4*

 

Omnibus Agreement, dated as of November 16, 2011, by and among LRR Energy, L.P., LRE GP, LLC, LRE Operating, LLC, LRR GP, LLC, Lime Rock Resources A, L.P., Lime Rock Resources B, L.P., Lime Rock Resources C, L.P. and Lime Rock Management LP (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on November 22, 2011).

 

 

 

10.5*

 

Services Agreement, dated as of November 16, 2011, by and among Lime Rock Management LP, Lime Rock Resources Operating Company, Inc., LRE GP, LLC, LRR Energy, L.P. and LRE

 

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Operating, LLC (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on November 22, 2011).

 

 

 

10.6

 

Amended and Restated Purchase, Sale, Contribution, Conveyance and Assumption Agreement, dated effective as of November 16, 2011, by and among Lime Rock Resources A, L.P., Lime Rock Resources B, L.P., Lime Rock Resources C, L.P., LRE GP, LLC, LRR Energy, L.P. and LRE Operating, LLC.

 

 

 

10.7*#

 

LRE GP, LLC Long-Term Incentive Plan, adopted as of November 10, 2011 (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on November 16, 2011).

 

 

 

10.8*#

 

Form of Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on November 16, 2011).

 

 

 

31.1

 

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

 

 

 

31.2

 

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

 

 

 

31.3

 

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

 

 

 

32.1

 

Certification by Co-Chief Executive Officers and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

101.INS**

 

XBRL Instance Document.

 

 

 

101.SCH**

 

XBRL Taxonomy Extension Schema Document.

 

 

 

101.CAL**

 

XBRL Taxonomy Extension Calculation Linkbase Document.

 

 

 

101.DEF**

 

XBRL Taxonomy Extension Definition Linkbase Document.

 

 

 

101.LAB**

 

XBRL Taxonomy Extension Label Linkbase Document.

 

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101.PRE**

 

XBRL Taxonomy Extension Presentation Linkbase Document.

 


* Incorporated by reference

** Submitted electronically herewith

# Compensatory plan or arrangement

 

In accordance with Rule 406T of Regulation S-T, the XBRL information in Exhibit 101 to this Quarterly Report on Form 10-Q shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act. The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

 

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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: December 20, 2011

 

 

 

 

By:

/s/ Eric Mullins

 

 

Eric Mullins

 

 

Co-Chief Executive Officer

 

 

 

 

 

 

Date: December 20, 2011

By:  

/s/ Jaime R. Casas

 

 

Jaime R. Casas
Vice President, Chief Financial Officer and Secretary
(Principal Financial Officer)

 

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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 3.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on November 22, 2011).

 

 

 

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*

 

Stakeholders’ Agreement, dated effective as of May 5, 2011, by and among LRR Energy, L.P., LRE GP, LLC, Lime Rock Resources GP, L.P., Lime Rock Resources A, L.P., Lime Rock Resources B, L.P., Lime Rock Resources C, L.P., Lime Rock Management LP, Lime Rock Resources GP II, L.P., Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P. (incorporated by reference to Exhibit 10.7 to the Partnership’s Registration Statement on Form S-1 (Registration No. 333-174017) filed on May 6, 2011).

 

 

 

10.2*

 

Credit Agreement, dated as of July 22, 2011, among LRE Operating, LLC, as Borrower, LRR Energy, L.P., as Parent Guarantor, the lenders from time to time party thereto, Wells Fargo Bank, National Association, as Administrative Agent, Bank of America, N.A., as Syndication Agent, and BNP Paribas, Citibank, N.A. and Royal Bank of Canada, as Co-Documentation Agents (incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on November 22, 2011).

 

 

 

10.3*

 

First Amendment to Credit Agreement, dated as of September 30, 2011, among LRE Operating, LLC, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.4 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on November 22, 2011).

 

 

 

10.4*

 

Omnibus Agreement, dated as of November 16, 2011, by and among LRR Energy, L.P., LRE GP, LLC, LRE Operating, LLC, LRR GP, LLC, Lime Rock Resources A, L.P., Lime Rock Resources B, L.P., Lime Rock Resources C, L.P. and Lime Rock Management LP (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on November 22, 2011).

 

 

 

10.5*

 

Services Agreement, dated as of November 16, 2011, by and among Lime Rock Management LP, Lime Rock Resources Operating Company, Inc., LRE GP, LLC, LRR Energy, L.P. and LRE Operating, LLC (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on November 22, 2011).

 

 

 

10.6

 

Amended and Restated Purchase, Sale, Contribution, Conveyance and Assumption Agreement, dated effective as of November 16, 2011, by and among Lime Rock Resources A, L.P., Lime Rock Resources B, L.P., Lime Rock Resources C, L.P., LRE GP, LLC.

 

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10.7*#

 

LRE GP, LLC Long-Term Incentive Plan, adopted as of November 10, 2011 (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on November 16, 2011).

 

 

 

10.8*#

 

Form of Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-35344), filed on November 16, 2011).

 

 

 

31.1

 

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

 

 

 

31.2

 

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

 

 

 

31.3

 

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

 

 

 

32.1

 

Certification by Co-Chief Executive Officers and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

101.INS**

 

XBRL Instance Document.

 

 

 

101.SCH**

 

XBRL Taxonomy Extension Schema Document.

 

 

 

101.CAL**

 

XBRL Taxonomy Extension Calculation Linkbase Document.

 

 

 

101.DEF**

 

XBRL Taxonomy Extension Definition Linkbase Document.

 

 

 

101.LAB**

 

XBRL Taxonomy Extension Label Linkbase Document.

 

 

 

101.PRE**

 

XBRL Taxonomy Extension Presentation Linkbase Document.

 


* Incorporated by reference

** Submitted electronically herewith

# Compensatory plan or arrangement

 

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In accordance with Rule 406T of Regulation S-T, the XBRL information in Exhibit 101 to this Quarterly Report on Form 10-Q shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act. The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

 

35