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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 March 31, 2012

 

OR

 

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

 

For the transition period from                    to                .

 

Commission File Number:  001-35344

 

LRR Energy, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware

 

90-0708431

(State or other jurisdiction of
incorporation or organization)

 

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

 

Heritage Plaza

1111 Bagby, Suite 4600

Houston, Texas

 

77002

(Address of principal executive offices)

 

(Zip code)

 

Telephone Number:  (713) 292-9510

(Registrant’s telephone number, including area code)

 


 

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

 

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

 

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

 

Large accelerated filer o

 

Accelerated filer 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 15,708,474 Common Units, 6,720,000 Subordinated Units and 22,400 General Partner Units outstanding as of May 4, 2012.  The Common Units trade on the New York Stock Exchange under the ticker symbol “LRE”.

 

 

 



Table of Contents

 

LRR Energy, L.P.

 

TABLE OF CONTENTS

 

 

 

Caption

 

Page

 

 

 

 

 

 

 

PART I — FINANCIAL INFORMATION

 

 

 

 

 

 

 

Item 1.

 

Financial Statements.

 

 

 

 

Unaudited Consolidated Condensed Balance Sheets as of March 31, 2012 and December 31, 2011

 

1

 

 

Unaudited Condensed Statements of Operations for the Three Months Ended March 31, 2012 (consolidated) and 2011 (combined)

 

2

 

 

Unaudited Consolidated Condensed Statement of Changes in Unitholders’ Equity as of March 31, 2012

 

3

 

 

Unaudited Condensed Statements of Cash Flows for the Three Months Ended March 31, 2012 (consolidated) and 2011 (combined)

 

4

 

 

Notes to Unaudited Consolidated/Combined Condensed Financial Statements

 

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.

 

29

Item 4.

 

Controls and Procedures.

 

29

 

 

 

 

 

 

 

PART II — OTHER INFORMATION

 

 

 

 

 

 

 

Item 1.

 

Legal Proceedings.

 

29

Item 1A.

 

Risk Factors.

 

29

Item 2.

 

Unregistered Sales of Equity Securities and Use of Proceeds.

 

30

Item 3.

 

Defaults Upon Senior Securities.

 

30

Item 4.

 

Mine Safety Disclosures.

 

30

Item 5.

 

Other Information.

 

30

Item 6.

 

Exhibits.

 

30

 

 

Signatures

 

32

 

i



Table of Contents

 

PART I—FINANCIAL INFORMATION

 

Item 1. Financial Statements.

 

LRR Energy, L.P.

Consolidated Condensed Balance Sheets

(Unaudited)

(in thousands, except unit amounts)

 

 

 

Partnership

 

 

 

March 31, 2012

 

December 31, 2011

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

6,803

 

$

1,513

 

Accounts receivable

 

8,947

 

12,924

 

Commodity derivative instruments

 

18,151

 

16,064

 

Amounts due from affiliates

 

665

 

 

Prepaid expenses

 

912

 

578

 

Total current assets

 

35,478

 

31,079

 

Property and equipment (successful efforts method)

 

651,735

 

644,188

 

Accumulated depletion, depreciation and impairment

 

(255,647

)

(245,581

)

Total property and equipment, net

 

396,088

 

398,607

 

Commodity derivative instruments

 

25,957

 

27,015

 

Interest rate derivative instruments

 

1,106

 

 

Deferred financing costs, net of accumulated amortization

 

1,291

 

1,365

 

TOTAL ASSETS

 

$

459,920

 

$

458,066

 

LIABILITIES AND UNITHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Trade accounts payable

 

$

1,005

 

$

2,707

 

Accrued liabilities

 

3,909

 

2,739

 

Accrued capital cost

 

4,011

 

1,421

 

Commodity derivative instruments

 

890

 

186

 

Amounts due to affiliates

 

 

536

 

Interest rate derivative instruments

 

302

 

 

Asset retirement obligations

 

365

 

359

 

Total current liabilities

 

10,482

 

7,948

 

Long-term liabilities:

 

 

 

 

 

Commodity derivative instruments

 

314

 

 

Revolving credit facility

 

155,800

 

155,800

 

Asset retirement obligations

 

22,976

 

22,780

 

Deferred tax liabilities

 

140

 

35

 

Total long-term liabilities

 

179,230

 

178,615

 

Total liabilities

 

189,712

 

186,563

 

Unitholders’ Equity:

 

 

 

 

 

General partner (22,400 units issued and outstanding as of March 31, 2012 and December 31, 2011)

 

436

 

438

 

Public common unitholders (10,608,000 units issued and outstanding as of March 31, 2012 and December 31, 2011)

 

188,961

 

189,537

 

Affiliated common unitholders (5,049,600 units issued and outstanding as of March 31, 2012 and December 31, 2011)

 

34,700

 

35,007

 

Subordinated unitholders (6,720,000 units issued and outstanding as of March 31, 2012 and December 31, 2011)

 

46,111

 

46,521

 

Total Unitholders’ Equity

 

270,208

 

271,503

 

TOTAL LIABILITIES AND UNITHOLDERS’ EQUITY

 

$

459,920

 

$

458,066

 

 

See accompanying notes to the unaudited consolidated/combined condensed financial statements

 

1



Table of Contents

 

LRR Energy, L.P.

Condensed Statements of Operations

(Unaudited)

(in thousands, except per unit amounts)

 

 

 

Partnership

 

 

Predecessor

 

 

 

Three Months Ended

 

 

Three Months Ended

 

 

 

March 31, 2012

 

 

March 31, 2011

 

 

 

(consolidated)

 

 

(combined)

 

Revenues:

 

 

 

 

 

 

Oil sales

 

$

10,971

 

 

$

16,403

 

Natural gas sales

 

5,223

 

 

10,825

 

Natural gas liquids sales

 

2,589

 

 

3,336

 

Realized gain on commodity derivative instruments

 

5,248

 

 

7,280

 

Unrealized gain (loss) on commodity derivative instruments

 

11

 

 

(19,233

)

Other income

 

3

 

 

39

 

Total revenues

 

24,045

 

 

18,650

 

 

 

 

 

 

 

 

Operating Expenses:

 

 

 

 

 

 

Lease operating expense

 

5,032

 

 

6,543

 

Production and ad valorem taxes

 

1,486

 

 

1,308

 

Depletion and depreciation

 

7,011

 

 

13,115

 

Impairment of oil and natural gas properties

 

3,093

 

 

 

Accretion expense

 

343

 

 

372

 

Gain on settlement of asset retirement obligations

 

(98

)

 

 

Management fees

 

 

 

1,472

 

General and administrative expense

 

2,847

 

 

1,696

 

Total operating expenses

 

19,714

 

 

24,506

 

 

 

 

 

 

 

 

Operating income (loss)

 

4,331

 

 

(5,856

)

 

 

 

 

 

 

 

Other income (expense), net

 

 

 

 

 

 

Interest income

 

 

 

4

 

Interest expense

 

(1,128

)

 

(289

)

Realized loss on interest rate derivative instruments

 

(33

)

 

(153

)

Unrealized gain on interest rate derivative instruments

 

805

 

 

127

 

Other income (expense), net

 

(356

)

 

(311

)

 

 

 

 

 

 

 

Income (loss) before taxes

 

3,975

 

 

(6,167

)

Income tax expense

 

(126

)

 

(43

)

Net income (loss)

 

$

3,849

 

 

(6,210

)

 

 

 

 

 

 

 

Computation of net income per limited partner unit:

 

 

 

 

 

 

 

 

 

 

 

 

 

General partners’ interest in net income

 

$

4

 

 

 

 

 

 

 

 

 

 

 

Limited partners’ interest in net income

 

$

3,845

 

 

 

 

 

 

 

 

 

 

 

Net income per limited partner unit

 

$

0.17

 

 

 

 

 

 

 

 

 

 

 

Weighted average number of limited partner units outstanding

 

22,421

 

 

 

 

 

See accompanying notes to the unaudited consolidated/combined condensed financial statements

 

2



Table of Contents

 

LRR Energy, L.P.

Consolidated Condensed Statement of Changes in Unitholders’ Equity

(Unaudited)

(in thousands)

 

 

 

 

 

Limited Partners

 

 

 

 

 

General

 

Public

 

Affiliated

 

 

 

 

 

Partner

 

Common

 

Common

 

Subordinated

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, December 31, 2011

 

$

438

 

$

189,537

 

$

35,007

 

$

46,521

 

$

271,503

 

Amortization of equity awards

 

 

69

 

 

 

69

 

Distribution

 

(5

)

(2,474

)

(1,173

)

(1,561

)

(5,213

)

Net income

 

3

 

1,829

 

866

 

1,151

 

3,849

 

Balance, March 31, 2012

 

$

436

 

$

188,961

 

$

34,700

 

$

46,111

 

$

270,208

 

 

See accompanying notes to the unaudited consolidated/combined condensed financial statements

 

3



Table of Contents

 

LRR Energy, L.P.

Condensed Statements of Cash Flows

(Unaudited)

(in thousands)

 

 

 

Partnership

 

 

Predecessor

 

 

 

Three Months Ended

 

 

Three Months Ended

 

 

 

March 31, 2012

 

 

March 31, 2011

 

 

 

(consolidated)

 

 

(combined)

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

 

Net income (loss)

 

$

3,849

 

 

$

(6,210

)

Adjustments to reconcile net income (loss) to net cash provided by

 

 

 

 

 

 

operating activities:

 

 

 

 

 

 

Depletion and depreciation

 

7,011

 

 

13,115

 

Impairment of oil and natural gas properties

 

3,093

 

 

 

Unrealized (gain) loss on derivative instruments, net

 

(816

)

 

19,106

 

Accretion expense

 

343

 

 

372

 

Amortization of equity awards

 

69

 

 

 

Amortization of deferred financing costs and other

 

74

 

 

23

 

Gain on settlement of asset retirement obligations

 

(98

)

 

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

Change in receivables

 

3,977

 

 

1,934

 

Change in prepaid expenses

 

(334

)

 

(3,983

)

Change in trade accounts payable and accrued liabilities

 

(427

)

 

(1,717

)

Change in amounts due from affiliates

 

(1,201

)

 

(77

)

Net cash provided by operating activities

 

15,540

 

 

22,563

 

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

 

Acquisition of oil and natural gas properties

 

(274

)

 

(410

)

Development of oil and natural gas properties

 

(4,747

)

 

(13,691

)

Expenditures for other property and equipment

 

(16

)

 

(40

)

Net cash used in investing activities

 

(5,037

)

 

(14,141

)

 

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

 

Deferred financing costs

 

 

 

(1

)

Capital contributions

 

 

 

1,766

 

Distributions

 

(5,213

)

 

(14,012

)

Net cash used in financing activities

 

(5,213

)

 

(12,247

)

 

 

 

 

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

 

5,290

 

 

(3,825

)

 

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD

 

1,513

 

 

12,455

 

 

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS, END OF PERIOD

 

$

6,803

 

 

$

8,630

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

Property and equipment:

 

 

 

 

 

 

Change in accrued capital costs

 

$

(2,590

)

 

$

3,634

 

Asset retirement obligations

 

(141

)

 

 

 

See accompanying notes to the unaudited consolidated/combined condensed financial statements

 

4



Table of Contents

 

LRR Energy, L.P.

Notes to Consolidated/Combined Condensed Financial Statements

(unaudited)

 

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 our IPO, 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. 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). IPO costs were approximately $4.7 million. Net proceeds of the offering, along with $155.8 million of borrowings under our new $500 million senior secured revolving credit agreement (Note 7) 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.

 

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 ($21.3 million) from the exercise of the underwriters’ option to purchase additional common units were 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.

 

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 (the “Partnership Properties”). Fund I received total consideration for the Partnership Properties of 5,049,600 common units, 6,720,000 subordinated units, $311.2 million in cash and the assumption of $27.3 million of LRR A’s indebtedness.

 

After reviewing applicable accounting literature, we consider the Partnership Properties to be under common control with Fund I. We have presented the combined historical financial statements of Fund I as our historical financial statements because we believe them to be “informative” to our investors and representative of our management’s ability to manage the Partnership Properties. The financial data and operations of Fund I are referred to herein as “predecessor.”

 

The following table presents the net assets conveyed by Fund I to the Partnership immediately prior to the closing of our IPO including the debt assumption (in thousands):

 

5



Table of Contents

 

Property and equipment, net

 

$

400,056

 

Derivative instruments

 

36,705

 

Total assets

 

$

436,761

 

 

 

 

 

Long-term debt

 

$

27,251

 

Derivative instruments

 

476

 

Asset retirement obligations

 

22,673

 

Total liabilities

 

$

50,400

 

 

 

 

 

Net assets

 

$

386,361

 

 

2.              Summary of Significant Accounting Policies

 

Our accounting policies are set forth in Note 2 of the audited consolidated/combined financial statements in our Annual Report on Form 10-K for the year ended December 31, 2011, and are supplemented by the notes to these unaudited consolidated/combined condensed financial statements. There have been no significant changes to these policies and these unaudited consolidated/combined condensed financial statements should be read in conjunction with the audited consolidated/combined financial statements and notes in our Annual Report on Form 10-K for the year ended December 31, 2011.

 

Basis of presentation

 

These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated/combined financial statements and should be read in conjunction with the audited consolidated/combined financial statements in our Annual Report on Form 10-K for the year ended December 31, 2011. 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 consolidated/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 December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities.” The amendments in this update require enhanced disclosures around financial instruments and derivative instruments that are either (1) offset in accordance with either ASC 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. The amendments are effective during interim and annual periods beginning on or after January 1, 2013. We do not expect this guidance to have any impact on our consolidated financial position, results of operations or cash flows.

 

In May 2011, the FASB issued ASU No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” The Amendments explain how to measure fair value and change the wording used to describe many of the fair value requirements in GAAP, but do not require additional fair value measurements. The guidance became effective for interim and annual periods beginning on or after December 15, 2011. We adopted these amendments on January 1, 2012 and they did not have a material impact on our consolidated financial position, results of operations or cash flows.

 

3.              Acquisitions and Divestitures

 

We did not acquire or divest any significant properties during the three months ended March 31, 2012 and 2011. We acquire proved oil and natural gas properties that meet management’s criteria with respect to reserve lives, development potential, production risk and other operational characteristics. We generally do not acquire assets

 

6



Table of Contents

 

other than oil and natural gas property interests. We assume the liability for asset retirement obligations (“ARO”) related to each acquisition and record the liability at fair value as of the date of closing.

 

Our acquisitions are accounted for under the acquisition method of accounting. Accordingly, we conduct 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 are expensed as incurred.

 

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.

 

Our acquisitions typically qualify as business combinations, and as such, we estimate 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, we use a discounted cash flow model and make 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. After post-closing and title adjustments, the assets acquired and liabilities assumed approximate fair value for the acquisitions.

 

4.              Fair Value Measurements

 

Our 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. Our financial and non-financial assets and liabilities that are measured on a recurring basis are measured and reported at fair value.

 

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

 

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

 

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

 

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

 

As required by GAAP, we utilize the most observable inputs available for the valuation technique used. The financial assets and liabilities are classified in their entirety based on the lowest level of input that is of significance to the fair value measurement. The following table describes, by level within the hierarchy, the fair value of the predecessor’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of the date indicated (in thousands).

 

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Level 1

 

Level 2

 

Level 3

 

Total

 

March 31, 2012

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

$

 

$

44,108

 

$

 

$

44,108

 

Interest rate derivative instruments

 

 

1,106

 

 

1,106

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

 

1,204

 

 

1,204

 

Interest rate derivative instruments

 

 

302

 

 

302

 

 

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

December 31, 2011

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

$

 

$

 

$

43,079

 

$

43,079

 

Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivative instruments

 

 

 

186

 

186

 

 

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

 

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

 

Interest Rate Derivative Instruments — The fair value of the interest rate derivative instruments is estimated using a combined income and market valuation methodology based upon forward interest rates and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes. We did not have any outstanding interest rate derivative instruments at December 31, 2011.

 

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 months ended March 31, 2012 and 2011 (in thousands):

 

 

 

Partnership

 

 

Predecessor

 

 

 

Three Months Ended

 

 

Three Months Ended

 

 

 

March 31, 2012

 

 

March 31, 2011

 

 

 

 

 

 

 

 

Balance at beginning of period

 

$

42,893

 

 

$

23,504

 

Total gains or losses (realized or unrealized):

 

 

 

 

 

 

Included in earnings

 

 

 

(11,979

)

Settlements

 

 

 

(7,127

)

Transfers in and out of Level 3 (1)

 

(42,893

)

 

 

Balance at end of period

 

$

 

 

$

4,398

 

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

 

$

816

 

 

$

(19,106

)

 


(1)         As part of a review by management of our fair value financial statement disclosures in light of ASU 2011-04, management has determined, effective January 1, 2012, the fair values of our derivative instruments should be classified as Level 2. Management has determined the prices quoted by the independent pricing service are observable inputs that management is able to independently test and corroborate for reasonableness through market prices.  Accordingly, on January 1, 2012, we transferred all derivative instruments which are measured on a recurring basis from Level 3 into Level 2.

 

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5.              Property and Equipment

 

The following table sets forth the components of property and equipment, net (in thousands):

 

 

 

March 31, 2012

 

December 31, 2011

 

Oil and natural gas properties (successful efforts method)

 

$

650,059

 

$

642,519

 

Unproved properties

 

1,358

 

1,367

 

Other property and equipment

 

318

 

302

 

 

 

651,735

 

644,188

 

Accumulated depletion, depreciation and impairment

 

(255,647

)

(245,581

)

Total property and equipment, net

 

$

396,088

 

$

398,607

 

 

For the three months ended March 31, 2012, due to a significant decline in future natural gas price curves across all future production periods, we performed an impairment analysis of our oil and natural gas properties and other non-current assets. The NYMEX-Henry Hub spot price for natural gas declined from $2.98 per MMBtu at December 31, 2011 to $1.98 per MMBtu at March 31, 2012. For the three months ended March 31, 2012, we recorded a total non-cash impairment charge of approximately $3.1 million to impair the value of our proved oil and natural gas properties in the Mid-Continent region. This non-cash charge is included in “Impairment of oil and natural gas properties” line item in the consolidated statements of operations. We did not record an impairment charge for the three months ended March 31, 2011.

 

The impairment of proved oil and natural gas properties was recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash flows reported in an internal reserve report. 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 oil and natural gas prices and basis differentials, anticipated drilling schedules, anticipated production declines, and an appropriate discount rate commensurate with the risk of the underlying cash flow estimates. Cash flow estimates for the impairment testing excluded derivative instruments used to mitigate the risk of lower future oil and natural gas prices. Significant assumptions in valuing the unproved reserves included the evaluation of the probable and possible reserves included in the internal reserve report, future expected oil and natural gas prices and basis differentials, and our anticipated drilling schedules.

 

This asset impairment has no impact on our cash flows, liquidity position, or debt covenants. If future oil or natural gas prices continue to decline during 2012, the estimated undiscounted future cash flows for the proved oil and natural gas properties may not exceed the net capitalized costs for our recently acquired properties and a non-cash impairment charge may be required to be recognized in future periods.

 

6.              Asset Retirement Obligations

 

The following is a summary of our ARO as of and for the three months ended March 31, 2012 (in thousands):

 

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Beginning of period

 

$

23,139

 

Revisions to previous estimates

 

(133

)

Liabilities incurred

 

81

 

Liabilities settled

 

(89

)

Accretion expense

 

343

 

End of period

 

23,341

 

Less: Current portion of asset retirement obligations

 

(365

)

Asset retirement obligations — non-current

 

$

22,976

 

 

7.              Long-Term Debt

 

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 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.

 

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 1.0x, and a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0x.

 

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. We were in compliance with our covenants as of March 31, 2012.

 

As of March 31, 2012 and December 31, 2011, we had approximately $155.8 million of outstanding debt and accrued interest was approximately $0.2 million and $0.5 million, respectively. Interest expense for the three months ended March 31, 2012 was approximately $1.1 million. Interest expense for the three months ended March 31, 2011 was approximately $0.3 million. Interest expense for the 2011 period related to LRR A’s credit facility. As of March 31, 2012 and December 31, 2011, the weighted average interest rate on our Credit Agreement was 2.83% and 2.86%, respectively.

 

We expect that our borrowing base will be redetermined by our lending group during the month of May. While our lending group will consider our recently announced acquisition of oil and natural gas reserves for $67 million in redetermining our borrowing base, we expect that our borrowing base will be slightly reduced by our lending group based upon their lower natural gas price assumptions. However, we expect to have the borrowing capacity to fund our announced acquisition that is scheduled to close on or about June 1, 2012. Further, we do not expect any anticipated reduction in our borrowing base to impact our operations, capital program, or ability to make quarterly cash distributions to our unitholders at currently anticipated levels.

 

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8.              Derivatives

 

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

 

At March 31, 2012 and December 31, 2011, our open positions consisted of contracts such as (i) crude oil and natural gas financial collar contracts, (ii) crude oil, NGL and natural gas financial swaps, (iii) natural gas basis financial swaps and (iv) interest rate swap agreements. Our derivative instruments are with the counterparties that are also lenders in our credit facility.

 

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

 

Under commodity swap agreements, we exchange a stream of payments over time according to specified terms with another counterparty. Specifically for commodity price swap agreements, we agree to pay an adjustable or floating price tied to an agreed upon index for the commodity, either gas or oil, and in return receive a fixed price based on notional quantities. Under basis swap agreements, we agree to pay an adjustable or floating price tied to two agreed upon indices for gas and in return receive the differential between a floating index and fixed price based on notional quantities. A collar is a combination of a put purchased by us and a call option written by us. In a typical collar transaction, if the floating price based on a market index is below the floor price, we receive from the counterparty an amount equal to this difference multiplied by the specified volume, effectively a put option. If the floating price exceeds the floor price and is less than the ceiling price, no payment is required by either party. If the floating price exceeds the ceiling price, we must pay the counterparty an amount equal to the difference multiplied by the specific quantity, effectively a call option.

 

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

 

We elected not to designate any positions as cash flow hedges for accounting purposes and, accordingly, recorded the net change in the mark-to-market valuation of these derivative contracts in the statements of operations. We record our derivative activities on a mark-to-market or fair value basis. Fair values are based on pricing models that consider 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, we present the fair value of derivative financial instruments on a net basis.

 

At March 31, 2012, we had the following open commodity derivative contracts:

 

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Table of Contents

 

 

 

Index

 

2012

 

2013

 

2014

 

2015

 

Natural gas positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (MMBTUs)

 

NYMEX-HH

 

2,701,256

 

5,757,645

 

5,107,055

 

4,596,205

 

Weighted average price

 

 

 

$

6.07

 

$

5.59

 

$

5.76

 

$

5.96

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis swaps (MMBTUs)

 

NYMEX

 

4,940,244

 

5,757,660

 

5,107,044

 

4,596,204

 

Weighted average price

 

 

 

$

(0.1130

)

$

(0.1447

)

$

(0.1575

)

$

(0.1715

)

 

 

 

 

 

 

 

 

 

 

 

 

Collars (MMBTUs)

 

NYMEX-HH

 

2,146,209

 

 

 

 

Floor-Ceiling price

 

 

 

$

4.75-7.31

 

$

 

$

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (BBLs)

 

NYMEX-WTI

 

274,230

 

289,323

 

248,149

 

219,657

 

Weighted average price

 

 

 

$

102.43

 

$

101.30

 

$

100.01

 

$

98.90

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL Positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (BBLs)

 

Mont Belvieu

 

125,599

 

123,750

 

 

 

Weighted average price

 

 

 

$

52.11

 

$

51.31

 

$

 

$

 

 

At December 31, 2011, we had the following open commodity derivative contracts:

 

 

 

Index

 

2012

 

2013

 

2014

 

2015

 

Natural gas positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (MMBTUs)

 

NYMEX-HH

 

3,684,189

 

5,757,645

 

5,107,055

 

4,596,205

 

Weighted average price

 

 

 

$

6.21

 

$

5.59

 

$

5.76

 

$

5.96

 

 

 

 

 

 

 

 

 

 

 

 

 

Collars (MMBTUs)

 

NYMEX-HH

 

2,902,801

 

 

 

 

Floor-Ceiling price

 

 

 

$

4.75-7.31

 

$

 

$

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (BBLs)

 

NYMEX-WTI

 

251,005

 

289,323

 

248,149

 

219,657

 

Weighted average price

 

 

 

$

102.20

 

$

101.30

 

$

100.01

 

$

98.90

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL Positions

 

 

 

 

 

 

 

 

 

 

 

Price swaps (BBLs)

 

Mont Belvieu

 

164,220

 

 

 

 

Weighted average price

 

 

 

$

49.92

 

$

 

$

 

$

 

 

At March 31, 2012, we had the following interest rate swap derivative contracts:

 

 

 

 

 

Notional

 

 

 

 

 

Effective

 

Maturity

 

Amount

 

Average %

 

Index

 

 

 

 

 

(in thousands)

 

 

 

 

 

February 2012

 

February 2015

 

$

150,000

 

0.5175

%

LIBOR

 

February 2015

 

February 2017

 

75,000

 

1.7250

%

LIBOR

 

February 2015

 

February 2017

 

75,000

 

1.7275

%

LIBOR

 

 

We did not have any outstanding interest rate swap derivative contracts as of December 31, 2011.

 

Effect of Derivative Instruments — Balance Sheet

 

The fair value of our commodity and interest rate derivative instruments as of March 31, 2012 is included in the table below (in thousands):

 

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Table of Contents

 

 

 

As of March 31, 2012

 

 

 

Current

 

Long-term

 

Current

 

Long-term

 

 

 

Assets

 

Assets

 

Liabilities

 

Liabilities

 

Interest rate

 

 

 

 

 

 

 

 

 

Swaps

 

$

 

$

1,106

 

$

302

 

$

 

Sale of Natural Gas Production

 

 

 

 

 

 

 

 

 

Price swaps

 

13,160

 

25,176

 

 

 

Basis swaps

 

7

 

 

31

 

167

 

Collars

 

4,833

 

 

 

 

Sale of Crude Oil Production

 

 

 

 

 

 

 

 

 

Price swaps

 

 

781

 

834

 

118

 

Sale of NGLs

 

 

 

 

 

 

 

 

 

Price swaps

 

151

 

 

25

 

29

 

 

 

$

18,151

 

$

27,063

 

$

1,192

 

$

314

 

 

The fair value of our commodity derivative instruments as of December 31, 2011 is included in the table below (in thousands):

 

 

 

As of December 31, 2011

 

 

 

Current

 

Long-term

 

Current

 

Long-term

 

 

 

Assets

 

Assets

 

Liabilities

 

Liabilities

 

Sale of Natural Gas Production

 

 

 

 

 

 

 

 

 

Price swaps

 

$

10,762

 

$

22,190

 

$

 

$

 

Collars

 

4,464

 

 

 

 

Sale of Crude Oil Production

 

 

 

 

 

 

 

 

 

Price swaps

 

838

 

4,825

 

 

 

Sale of NGLs

 

 

 

 

 

 

 

 

 

Price swaps

 

 

 

186

 

 

 

 

$

16,064

 

$

27,015

 

$

186

 

$

 

 

Effect of Derivative Instruments — Statement of Operations

 

The unrealized and realized gain or loss amounts and classification related to derivative instruments for the three months ended March 31, 2012 and 2011 are as follows (in thousands):

 

 

 

Partnership

 

 

Predecessor

 

 

 

Three Months Ended

 

 

Three Months Ended

 

 

 

March 31, 2012

 

 

March 31, 2011

 

 

 

 

 

 

 

 

Realized gains (losses):

 

 

 

 

 

 

Commodity derivatives (revenue)

 

$

5,248

 

 

$

7,280

 

Interest rate derivatives (other income/expense)

 

(33

)

 

(153

)

Unrealized gains (losses):

 

 

 

 

 

 

Commodity derivatives (revenue)

 

11

 

 

(19,233

)

Interest rate derivatives (other income/expense)

 

805

 

 

127

 

 

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

 

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quality and have the financial resources and willingness to meet our potential repayment obligations associated with the derivative transactions.

 

9.              Related Parties

 

Ownership in Our General Partner by the Management of Fund I and its Affiliates

 

As of March 31, 2012, Lime Rock Management, an affiliate of Fund I, owned all of the Class A member interests in our general partner. Fund I owned all of the Class B member interests in our general partner and Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P. owned all of the Class C member interests in our general partner. In addition, Fund I owned an aggregate of approximately 32.1% of our outstanding common units and all of our subordinated units representing limited partner interests in us. In addition, our general partner owned an approximate 0.1% general partner interest in us, represented by 22,400 general partner units, and all of our incentive distribution rights.

 

Contracts with our General Partner and its Affiliates

 

We have entered into agreements with our general partner and its affiliates. Refer to Note 1 in the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2011 for a description of those agreements. For the three months ended March 31, 2012, we paid Lime Rock Management approximately $0.2 million, either directly or indirectly, related to these agreements.

 

Distributions of Available Cash to Our General Partner and Affiliates

 

We will generally make cash distributions to our unitholders and our general partner pro rata. As of March 31, 2012, our general partner and its affiliates held 5,049,600 of our common units, all of our subordinated units and 22,400 general partner units. On February 14, 2012, we paid a pro-rated cash distribution of $0.2323 per outstanding unit. The pro-rated amount corresponded to our minimum quarterly cash distribution of $0.4750 per unit, or $1.90 on an annualized basis. The proration period began on November 17, 2011, the day after the closing date of LRR Energy’s initial public offering, and ended December 31, 2011. The aggregate amount of the distribution was $5.2 million.

 

We announced our first quarter 2012 distribution on April 13, 2012 as discussed in Note 13.

 

Predecessor 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 months ended March 31, 2011, the predecessor expensed $1.5 million in management fees to Lime Rock Management.

 

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 months ended March 31, 2011, the predecessor received $0.3 million, of income, which reduced the management fee paid by the predecessor to Lime Rock Management. 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.       Unitholders’ Equity

 

Initial Public Offering

 

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). IPO

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costs were approximately $4.7 million. We reimbursed Fund I for all costs they paid related to our IPO ($3.2 million). Net proceeds of the offering, along with $155.8 million of borrowings under our new $500 million senior secured revolving credit agreement, 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.

 

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. We used the net proceeds from the sale of the additional common units of $21.3 million, after deducting underwriting discounts and a structuring fee, 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. In connection with our IPO, Fund I received total consideration for the Partnership Properties of 5,049,600 common units, 6,720,000 subordinated units, $311.2 million in cash and the assumption of $27.3 million of LRR A’s indebtedness.

 

Units Outstanding

 

As of March 31, 2012, we had 15,708,474 common units, 6,720,000 subordinated units and 22,400 general partner units outstanding. In addition, as of March 31, 2012, Fund I owned 5,049,600 common units and all of our subordinated units, representing a 52.4% limited partner interest in us.

 

11.       Net Income Per Limited Partner Unit

 

The following sets forth the calculation of net income per limited partner unit for the three months ended March 31, 2012 (in thousands, except per unit amounts):

 

Net income

 

$

3,849

 

Less: General partner’s 0.1% interest in net income

 

(4

)

Limited partners’ interest in net income

 

$

3,845

 

 

 

 

 

Weighted average limited partner units outstanding:

 

 

 

Common units

 

15,701

 

Subordinated units

 

6,720

 

Total

 

22,421

 

 

 

 

 

Net income per limited partner unit (basic and diluted)

 

$

0.17

 

 

Our subordinated units and restricted unit awards are considered to be participating securities for purposes of calculating our net income per limited partner unit, and accordingly, are included in basic computation as such. Net income per limited partner unit is determined by dividing the net income available to the common unitholders, after deducting our general partner’s approximate 0.1% interest in net income, by weighted average number of common units and subordinated units outstanding as of March 31, 2012. The aggregate number of common units and subordinated units outstanding was 15,708,474 and 6,720,000, respectively, as of March 31, 2012.

 

12.       Equity-Based Compensation

 

On November 10, 2011, our general partner adopted a long-term incentive plan (“2011 LTIP”) for employees, consultants and directors of our general partner and its affiliates, including Lime Rock Management and Lime Rock Resources Operating Company, Inc., who perform services for us. The 2011 LTIP consists of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, unit awards and other unit-based awards. The 2011 LTIP initially limits the number of units that may be delivered pursuant to vested awards to 1,500,000 common units. As of March 31, 2012, there were 1,449,126 units available for issuance under the 2011 LTIP. The 2011 LTIP is currently administered by our general partner’s board of directors.

 

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

 

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Table of Contents

 

A summary of the status of the non-vested units as of March 31, 2012, is presented below:

 

 

 

 

 

Weighted

 

 

 

Number of

 

Average

 

 

 

Non-vested

 

Grant-Date

 

 

 

Units

 

Fair Value

 

Non-vested restricted units at January 1, 2012

 

42,474

 

$

18.88

 

Granted

 

8,400

 

20.89

 

Vested

 

 

 

Forfeited

 

 

 

Non-vested units at March 31, 2012

 

50,874

 

$

19.21

 

 

As of March 31, 2012, there was approximately $0.9 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over a weighted average period of approximately 2.7 years. There were no vested restricted units as of March 31, 2012.

 

13.       Subsequent Events

 

On April 13, 2012, we announced that the board of directors of our general partner declared a cash distribution for the first quarter of 2012 of $0.4750 per outstanding unit, or $1.90 on an annualized basis. The distribution will be paid on May 14, 2012 to all unitholders of record as of the close of business on April 27, 2012. The aggregate amount of the distribution will be approximately $10.7 million.

 

On May 2, 2012, we announced that we signed a definitive agreement to acquire certain oil and natural gas properties in the Permian Basin region in New Mexico and onshore Gulf Coast region in Texas from Fund I, for a purchase price of $67.0 million. We expect to finance the transaction with borrowings under our revolving credit facility. Terms of the transaction were approved on May 2, 2012 by the board of directors of our general partner and on May 1, 2012 by the board’s conflicts committee, which is comprised entirely of independent directors. The transaction is expected to close on or about June 1, 2012, subject to customary approvals and closing conditions.

 

In connection with the acquisition announced in May 2012, we entered into the following commodity hedges:

 

 

 

Index

 

2012

 

2013

 

2014

 

2015

 

2016

 

Gas Hedges

 

 

 

 

 

 

 

 

 

 

 

 

 

Price swaps (MMBtus)

 

NYMEX-HH

 

124,355

 

170,680

 

135,915

 

111,520

 

95,710

 

Weighted average price

 

 

 

$

2.61

 

$

3.46

 

$

3.87

 

$

4.08

 

$

4.27

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Hedges

 

 

 

 

 

 

 

 

 

 

 

 

 

Price swaps (Bbls)

 

NYMEX-WTI

 

67,745

 

93,330

 

84,235

 

70,295

 

61,413

 

Weighted average price

 

 

 

$

106.00

 

$

103.75

 

$

98.23

 

$

93.55

 

$

89.90

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL Hedges

 

 

 

 

 

 

 

 

 

 

 

 

 

Price swaps (Bbls)

 

Mont Belvieu

 

14,876

 

20,573

 

 

 

 

Weighted average price

 

 

 

$

46.48

 

$

45.56

 

$

 

$

 

$

 

 

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Table of Contents

 

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

 

Cautionary Note Regarding Forward-Looking Statements

 

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

 

·                  business strategies;

·                  ability to replace the reserves we produce through drilling and property acquisitions;

·                  drilling locations;

·                  oil and natural gas reserves;

·                  technology;

·                  realized oil and natural gas prices;

·                  production volumes;

·                  lease operating expenses;

·                  general and administrative expenses;

·                  future operating results;

·                  cash flows and liquidity;

·                  availability of drilling and production equipment;

·                  general economic conditions;

·                  effectiveness of risk management activities; and

·                  plans, objectives, expectations and intentions.

 

All statements, other than statements of historical fact, are forward-looking statements. These forward-looking statements can be identified by their use of terms and phrases such as “may,” “predict,” “pursue,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “target,” “continue,” “potential,” “should,” “could” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties some of which are beyond our control. Actual results could differ materially from those anticipated in these forward-looking statements. One should consider carefully the risk factors described in Item 1A. “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2011 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;

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

·                  electronic, cyber, and physical security breaches;

·                  general economic conditions; and

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

 

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Table of Contents

 

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

 

Overview

 

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

 

In connection with the completion of our 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 (the “Partnership Properties”) owned by LRR A, LRR B, and LRR C. The underwriters partially exercised their option to purchase additional units and on December 14, 2011, we issued an additional 1,200,000 units to the public. The net proceeds from the exercise of the underwriters’ option to purchase additional common units were 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.

 

Fund I received total consideration for the Partnership Properties of 5,049,600 common units, 6,720,000 subordinated units, $311.2 million in cash and the assumption of $27.3 million of LRR A’s indebtedness. For further discussion regarding our IPO, please see Note 1 to the consolidated/combined condensed financial statements included in this report.

 

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

 

Our discussion and analysis of the results of operations below discusses the partnership and predecessor’s results of operations separately. Beginning with our Quarterly Report on Form 10-Q for the quarter ended June 30, 2012, we expect we will compare the current quarterly results with the most recent prior quarter until we are able to discuss changes between comparable interim periods. We expect we will compare our results of operations between comparable interim periods beginning with our Quarterly Report on Form 10-Q for the quarter ending March 31, 2013.

 

Results of Operations

 

The table below summarizes certain of the results of operations attributable to us and our predecessor for the periods indicated. Because the historical 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 historical results of our predecessor to be indicative of our future results. Nevertheless, they are presented here for illustrative purposes only to provide a possible context for our current operations.

 

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Table of Contents

 

 

 

Partnership

 

 

Predecessor

 

 

 

Three Months Ended

 

November 16, to

 

 

Three Months Ended

 

 

 

March 31, 2012

 

December 31, 2011

 

 

March 31, 2011

 

Revenues (in thousands):

 

 

 

 

 

 

 

 

Oil sales

 

$

10,971

 

$

6,118

 

 

$

16,403

 

Natural gas sales

 

5,223

 

3,482

 

 

10,825

 

Natural gas liquids sales

 

2,589

 

1,567

 

 

3,336

 

Realized gain (loss) on commodity derivative instruments

 

5,248

 

4,015

 

 

7,280

 

Unrealized gain (loss) on commodity derivative instruments

 

11

 

6,664

 

 

(19,233

)

Other income

 

3

 

 

 

39

 

Total revenues

 

24,045

 

21,846

 

 

18,650

 

 

 

 

 

 

 

 

 

 

Expenses (in thousands):

 

 

 

 

 

 

 

 

Lease operating expense

 

5,032

 

2,441

 

 

6,543

 

Production and ad valorem taxes

 

1,486

 

850

 

 

1,308

 

Depletion and depreciation

 

7,011

 

3,923

 

 

13,115

 

Impairment of oil and natural gas properties

 

3,093

 

 

 

 

Management fees

 

 

 

 

1,472

 

General and administrative expense

 

2,847

 

1,662

 

 

1,696

 

Interest expense

 

1,128

 

604

 

 

289

 

Realized loss on interest rate derivative instruments

 

33

 

 

 

153

 

 

 

 

 

 

 

 

 

 

Production:

 

 

 

 

 

 

 

 

Oil (MBbls)

 

112

 

65

 

 

186

 

Natural gas (MMcf)

 

1,964

 

1,038

 

 

2,626

 

NGLs (MBbls)

 

52

 

27

 

 

70

 

Total (MBoe)

 

491

 

265

 

 

694

 

Average net production (Boe/d)

 

5,396

 

5,761

 

 

7,707

 

 

 

 

 

 

 

 

 

 

Average sales price:

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

 

 

 

 

 

 

 

Sales price

 

$

97.96

 

$

94.12

 

 

$

88.19

 

Effect of realized commodity derivative instruments

 

(0.38

)

11.03

 

 

6.77

 

Realized price

 

$

97.58

 

$

105.15

 

 

$

94.96

 

Natural gas (per Mcf)

 

 

 

 

 

 

 

 

Sales price

 

$

2.66

 

$

3.35

 

 

$

4.12

 

Effect of realized commodity derivative instruments

 

2.69

 

3.20

 

 

2.29

 

Realized price

 

$

5.35

 

$

6.55

 

 

$

6.41

 

NGLs (per Bbl)

 

 

 

 

 

 

 

 

Sales price

 

$

49.79

 

$

58.04

 

 

$

47.66

 

Effect of realized commodity derivative instruments

 

0.12

 

(0.93

)

 

 

Realized price

 

$

49.91

 

$

57.11

 

 

$

47.66

 

 

 

 

 

 

 

 

 

 

Average unit cost per Boe:

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

10.24

 

$

9.21

 

 

$

9.43

 

Production and ad valorem taxes

 

3.02

 

3.21

 

 

1.88

 

Depletion and depreciation

 

14.27

 

14.80

 

 

18.90

 

Management fees

 

 

 

 

2.12

 

General and administrative expenses

 

5.79

 

6.27

 

 

2.44

 

 

Our Results for the Three Months Ended March 31, 2012

 

We recorded net income of $3.8 million during the three months ended March 31, 2012.  Our net income was primarily driven by total revenues of $24.0 million offset by lease operating expenses of $5.0 million, production and ad valorem taxes of $1.5 million, depletion and depreciation of $7.0 million, an impairment charge of $3.1 million and general and administrative expenses of $2.8 million.

 

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Table of Contents

 

Sales Revenues.  Sales revenues of $18.8 million for the period consisted of oil sales of $11.0 million, natural gas sales of $5.2 million and NGL sales of $2.6 million. Our production volumes for the period included 164 MBbls of oil and NGLs and 1,964 MMcf of natural gas, or 1,802 Bbl/d of oil and NGLs and 21,582 Mcf/d of natural gas. On an equivalent basis, production for the period was 491 MBoe, or 5,396 Boe/d.

 

Our average sales price per Bbl for oil and NGLs for the period, excluding the effect of commodity derivative contracts, was $97.96 and $49.79, respectively. Our average sales price per Mcf of natural gas, excluding the effect of commodity derivative contracts, was $2.66.

 

During the third week in February 2012 and through the second week in March 2012, approximately 1,515 Bbls/d and 1.7 MMcf/d of our Red Lake field production was entirely shut-in due to a compression system upgrade at the third party gas plant that processes natural gas for our Red Lake field. The upgrade was initially expected to last 7 days, but it experienced delays and took 21 days to complete. We are currently producing approximately 1,900 Boe per day from the Red Lake field, which is approximately 105% of pre-curtailment daily production volumes.

 

Relating to the Pecos Slope field curtailment disclosed in our Annual Report on Form 10-K for the year ended December 31, 2011, approximately 1.3 MMcf/d of production was curtailed in January and February 2012 due to the gas containing a nitrogen percentage greater than our gas purchaser’s specification. Beginning in late February of 2012, the curtailment was reduced and is currently approximately 0.8 MMcf/d and is expected to remain at this level until the field-wide nitrogen rejection facility is installed in October 2012 by the gas gathering company. The actual timing and amount of resumed production may differ from these estimates.

 

Effects of Commodity Derivative Contracts.  Due to changes in oil and natural gas prices, we recorded a net gain from our commodity hedging program for the period of approximately $5.3 million, which is comprised of a realized gain of approximately $5.2 million and an unrealized gain of less than $0.1 million.

 

Lease Operating Expenses.  Our lease operating expenses were approximately $5.0 million, or $10.24 per Boe, for the period. The per Boe amount is higher than the period from November 16 to December 31, 2011 due to lower production caused by the curtailment and shut-in discussed above.

 

Production and Ad Valorem Taxes.  Our production and ad valorem taxes were approximately $1.5 million, or $3.02 per Boe, for the period. The per Boe amount is consistent with the period from November 16 to December 31, 2011. Production taxes accounted for approximately $1.3 million and ad valorem taxes for $0.2 million of the total taxes recorded.

 

Depletion and Depreciation.  Our depletion and depreciation expense was approximately $7.0 million, or $14.27 per Boe, for the period. The per Boe amount is consistent with the period from November 16 to December 31, 2011.

 

Impairment of Oil and Natural Gas Properties.  We recorded an impairment of approximately $3.1 million for the three months ended March 31, 2012 due to a decline in natural gas prices during the period. If future oil or natural gas prices decline further during 2012, the estimated undiscounted future cash flows for the proved oil and natural gas properties may not exceed the net capitalized costs for our recently acquired properties and a non-cash impairment charge may be required to be recognized in future periods. As of May 7, 2012, the NYMEX-WTI oil spot price was $97.94 per Bbl and the NYMEX-Henry Hub natural gas spot price was $2.30 per MMBtu.

 

General and Administration Expenses.  Our general and administrative expenses were approximately $2.8 million, or $5.79 per Boe, for the three months ended March 31, 2012. The per Boe amount is lower than the period from November 16 to December 31, 2011 due to additional payroll costs in the 2011 period related to allocated bonuses.

 

Interest Expenses.  Our interest expense is comprised of interest on our credit facility, amortization of debt issuance costs and realized gains (losses) on our interest rate derivative instruments. Interest expense was approximately $1.2 million for the three months ended March 31, 2012.

 

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Table of Contents

 

Our Predecessor’s Results for the Three Months Ended March 31, 2011

 

Our predecessor recorded a net loss of approximately $6.2 million for the three months ended March 31, 2011. Net loss was primarily driven by total revenues of $18.6 million offset by lease operating expenses of $6.5 million, production and ad valorem taxes of $1.3 million, depletion and depreciation of $13.1 million, management fees of $1.5 million and general and administrative expenses of $1.7 million.

 

Sales Revenues.  Sales revenues of $30.5 million for the period consisted of oil sales of $16.4 million, natural gas sales of $10.8 million and NGL sales of $3.3 million. Our predecessor’s production volumes for the period included 256 MBbls of oil and NGLs and 2,626 MMcf of natural gas, or 2,844 Bbl/d of oil and NGLs and 29,178 Mcf/d of natural gas. On an equivalent basis, production for the period was 694 MBoe, or 7,707 Boe/d.

 

Our predecessor’s average sales price per Bbl for oil and NGLs for the period, excluding the effect of commodity derivative contracts, was $88.19 and $47.66, respectively. Our predecessor’s average sales price per Mcf of natural gas, excluding the effect of commodity derivative contracts, was $4.12.

 

Effects of Commodity Derivative Contracts.  Due to changes in oil and natural gas prices, our predecessor recorded a net loss from its commodity hedging program for the period of approximately $11.9 million, which is comprised of a realized gain of approximately $7.3 million and an unrealized loss of approximately $19.2 million.

 

Lease Operating Expenses.  Our predecessor’s lease operating expenses were approximately $6.5 million, or $9.43 per Boe, for the period. Our predecessor’s lease operating expenses were impacted by approximately $1.2 million of additional expenses at one of our predecessor’s fields in New Mexico related to increased saltwater disposal costs.

 

Production and Ad Valorem Taxes.  Our predecessor’s production and ad valorem taxes were approximately $1.3 million, or $1.88 per Boe, for the period. Production and ad valorem taxes were low primarily due to changes in the estimates of the appraisals on which property taxes were calculated.

 

Depletion and Depreciation.  Our predecessor’s depletion and depreciation expense for the period was approximately $13.1 million, or $18.90 per Boe.

 

Impairment of Oil and Natural Gas Properties.  Our predecessor did not record any impairment charges during the period.

 

Management Fees.  Our predecessor incurred a management fee paid to Lime Rock Management in addition to the direct general and administrative expenses it incurred. The management fee was determined by a formula based on our predecessor’s limited partners’ invested capital or the entity capital commitment in Fund I. Our predecessor’s management fees were approximately $1.5 million for the period.

 

General and Administration Expenses.  Our predecessor’s general and administrative expenses for the period were approximately $1.7 million, or $2.44 per Boe.

 

Interest Expenses.  Our predecessor’s interest expense is comprised of interest on its credit facility, amortization of debt issuance costs and realized gains (losses) on its interest rate derivative instruments. Interest expense was approximately $0.4 million for the period.

 

Non-GAAP Financial Measures

 

Below we disclose the non-GAAP financial measures Adjusted EBITDA, Distributable Cash Flow and Distribution Coverage Ratio for the periods presented and provide reconciliations of these items to net income and net cash provided by operating activities, our most directly comparable financial performance and liquidity measures calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income (loss):

 

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Table of Contents

 

·                  Plus:

 

·                  Income tax expense (benefit);

·                  Interest expense-net, including realized and unrealized losses on interest rate derivative contracts;

·                  Depletion and depreciation;

·                  Accretion of asset retirement obligations;

·                  Amortization of equity awards;

·                  Gain (loss) on settlement of asset retirement obligations;

·                  Unrealized losses on commodity derivative contracts;

·                  Impairment of oil and natural gas properties; and

·                  Other non-recurring items that we deem appropriate.

 

·                  Less:

 

·                  Interest income;

·                  Unrealized gains on commodity derivative contracts; and

·                  Other non-recurring items that we deem appropriate.

 

We define Distributable Cash Flow as Adjusted EBITDA less income tax expense; cash interest expense, net of realized losses on interest rate swaps; and estimated maintenance capital expenditures. Distribution Coverage Ratio is defined as the ratio of Distributable Cash Flow to the total quarterly distribution payable on all of our outstanding common, subordinated and general partner units.

 

Adjusted EBITDA, Distributable Cash Flow and Distribution Coverage Ratio are used as supplemental financial measures by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess:

 

·                  our operating performance as compared to that of other companies and partnerships in our industry, without regard to financing methods, capital structure or historical cost basis;

·                  the ability of our assets to generate sufficient cash flow to make distributions to our unitholders; and

·                  our ability to incur and service debt and fund capital expenditures.

 

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

 

Our Adjusted EBITDA for the three months ended March 31, 2012 and the period from November 16 to December 31, 2011 was approximately $14.7 million and $10.3 million, respectively. Our predecessor’s Adjusted EBITDA for the three months ended March 31, 2011 was approximately $26.9 million. Our Distributable Cash Flow for the three months ended March 31, 2012 and the period from November 16 to December 31, 2011 was approximately $8.7 million and $8.0 million, respectively. Our Distribution Coverage Ratio for the three months ended March 31, 2012 and the period from November 16 to December 31, 2011 was approximately 0.82 and 1.53, respectively.

 

The following table presents a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.

 

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Table of Contents

 

Reconciliation of Adjusted EBITDA to Net Income

 

 

 

Partnership

 

 

Predecessor

 

 

 

Three Months Ended

 

November 16, to

 

 

Three Months Ended

 

(in thousands)

 

March 31, 2012

 

December 31, 2011

 

 

March 31, 2011

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

3,849

 

$

12,150

 

 

$

(6,210

)

Income tax expense

 

126

 

48

 

 

43

 

Interest expense-net, including realized and unrealized losses on interest rate derivative instruments

 

356

 

604

 

 

315

 

Depletion and depreciation

 

7,011

 

3,923

 

 

13,115

 

Accretion of asset retirement obligations

 

343

 

168

 

 

372

 

Amortization of equity awards

 

69

 

31

 

 

 

Gain on settlement of asset retirement obligations

 

(98

)

 

 

 

Unrealized losses on commodity derivative instruments

 

 

 

 

19,233

 

Impairment of oil and natural gas properties

 

3,093

 

 

 

 

Interest income

 

 

 

 

(4

)

Unrealized gain on commodity derivative instruments

 

(11

)

(6,664

)

 

 

Adjusted EBITDA

 

$

14,738

 

$

10,260

 

 

$

26,864

 

 

Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities

 

 

 

Partnership

 

 

Predecessor

 

 

 

Three Months Ended

 

November 16, to

 

 

Three Months Ended

 

(in thousands)

 

March 31, 2012

 

December 31, 2011

 

 

March 31, 2011

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

15,540

 

$

2,173

 

 

$

22,563

 

Change in working capital

 

(2,015

)

7,485

 

 

3,843

 

Interest expense-net

 

1,087

 

554

 

 

415

 

Income tax expense

 

126

 

48

 

 

43

 

Adjusted EBITDA

 

$

14,738

 

$

10,260

 

 

$

26,864

 

 

Distributable Cash Flow and Distribution Coverage Ratio

 

The following table presents a reconciliation of Distributable Cash Flow and Distribution Coverage Ratio to Adjusted EBITDA for each of the periods presented. Adjusted EBITDA is reconciled to net income and net cash provided by operating activities, our most directly comparable GAAP performance and liquidity measures, above.

 

 

 

Partnership

 

 

 

Three Months Ended

 

November 16, to

 

(in thousands)

 

March 31, 2012

 

December 31, 2011

 

 

 

 

 

 

 

Adjusted EBITDA

 

$

14,738

 

$

10,260

 

Income tax expense

 

(126

)

(48

)

Cash interest expense

 

(1,410

)

 

Estimated maintenance capital (1)

 

(4,500

)

(2,250

)

Distributable Cash Flow

 

$

8,702

 

$

7,962

 

Cash distribution

 

$

10,664

 

$

5,213

 

Distribution Coverage Ratio

 

0.82x

 

1.53x

 

 


(1)         Estimated annual maintenance capital was $18 million for 2012 and 2011.  Amount represents pro-rated capital for the period outstanding.

 

23



Table of Contents

 

Liquidity and Capital Resources

 

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

 

Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our credit facility. We may issue additional equity and debt as needed.

 

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

 

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