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LRE > SEC Filings for LRE > Form 10-Q on 7-May-2014All Recent SEC Filings

Show all filings for LRR ENERGY, L.P.

Form 10-Q for LRR ENERGY, L.P.


7-May-2014

Quarterly Report


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

              Cautionary Note Regarding Forward-Looking Statements



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



          business strategies;

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

          drilling locations;

          oil and natural gas reserves;

          technology;

          realized oil and natural gas prices;

          production volumes;

          lease operating expenses;

          general and administrative expenses;

          future operating results;

          cash flows and liquidity;

          availability of drilling and production equipment;

          general economic conditions;

          effectiveness of risk management activities; and

          plans, objectives, expectations and intentions.

All statements, other than statements of historical fact, are forward-looking statements. These forward-looking statements can be identified by their use of terms and phrases such as "may," "predict," "pursue," "expect," "estimate," "project," "plan," "believe," "intend," "achievable," "anticipate," "target," "continue," "potential," "should," "could" and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties some of which are beyond our control. Actual results could differ materially from those anticipated in these forward-looking statements. One should consider carefully the risk factors described in Item 1A. "Risk Factors" of our Annual Report on Form 10-K for the year ended December 31, 2013 ("2013 Annual Report") that describe factors that could cause our actual results to differ from those anticipated in the forward-looking statements, including, but not limited to, the following factors:

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

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

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

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

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

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

          uncertainty inherent in estimating our reserves;

          the risks and uncertainties involved in developing and producing oil

and natural gas;

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

          competition in the oil and natural gas industry;

          cash flows and liquidity;

          restrictions and financial covenants in our credit facility and term
loan;

          the availability of pipelines, transportation and gathering systems

and processing facilities owned by third parties;

electronic, cyber, and physical security breaches;

general economic conditions; and


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

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

Overview

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

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

Contribution of Properties

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

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

Results of Operations

The January 2013 Acquisition and April 2013 Acquisition were deemed to be transactions between entities under common control. As a result, our historical financial statements were revised to include the activities of such assets for all periods presented, similar to a pooling of interests, to include the financial position, results of operations and cash flows of the assets acquired and liabilities assumed. Please refer to our 2013 Annual Report regarding the recast of financial information for transactions between entities under common control. The table set forth below includes recast historical financial and operating information attributable to previous acquisitions from Fund I and Fund II as if we owned the properties for all periods presented in our consolidated financial statements.


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                                                     Three Months Ended March 31,
                                                       2014               2013
Revenues (in thousands):
Oil sales                                         $        20,156    $        15,463
Natural gas sales                                           8,099              6,080
Natural gas liquids sales                                   3,364              2,235
Loss on commodity derivative instruments, net              (5,622 )           (6,067 )
Other income                                                   31                 69
Total revenues                                             26,028             17,780

Expenses (in thousands):
Lease operating expense                                     5,835              6,797
Production and ad valorem taxes                             2,400              1,846
Depletion and depreciation                                  8,465             10,110
General and administrative expense                          3,182              3,429
Interest expense                                            2,541              2,265
Loss (gain) on interest rate derivative
instruments, net                                              294               (115 )

Production:
Oil (MBbls)                                                   218                188
Natural gas (MMcf)                                          1,622              1,808
NGLs (MBbls)                                                   85                 72
Total (MBoe)                                                  573                561
Average net production (Boe/d)                              6,367              6,233

Average sales price:
Oil (per Bbl):
Sales price                                       $         92.46    $         82.25
Effect of settled commodity derivative
instruments                                                 (0.79 )             1.26
Realized price                                    $         91.67    $         83.51
Natural gas (per Mcf):
Sales price                                       $          4.99    $          3.36
Effect of settled commodity derivative
instruments                                                  0.53               1.95
Realized price                                    $          5.52    $          5.31
NGLs (per Bbl):
Sales price                                       $         39.58    $         31.04
Effect of settled commodity derivative
instruments                                                 (3.78 )             4.71
Realized price                                    $         35.80    $         35.75

Average unit cost per Boe:
Lease operating expenses                          $         10.18    $         12.11
Production and ad valorem taxes                              4.19               3.29
Depletion and depreciation                                  14.76              18.01
General and administrative expenses                          5.55               6.11

Our Results for the Three Months Ended March 31, 2014 Compared to the Three Months Ended March 31, 2013

We recorded net income of $2.7 million for the three months ended March 31, 2014 compared to net loss of $7.0 million during the three months ended March 31, 2013, primarily related to higher revenues and lower operating expenses. The following discussion summarizes key components of the changes between periods.


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Sales Revenues. A summary of increases (decreases) in our oil, natural gas and NGL revenues between the three months ended March 31, 2013 and March 31, 2014 follows (in thousands):

Oil, natural gas and NGL revenues-prior period     $ 23,778
Increase (decrease)
Price realization
Oil                                                   1,919
Natural gas                                           2,946
NGLs                                                    615
Sales volumes
Oil                                                   2,774
Natural gas                                            (928 )
NGLs                                                    515
Oil, natural gas and NGL revenues-current period   $ 31,619

Sales revenues increased from $23.8 million for the three months ended March 31, 2013 to $31.6 million for the three months ended March 31, 2014, primarily due to higher commodity price realizations and oil and NGL sales volumes offset by lower natural gas volumes. Sales revenues for the three months ended March 31, 2014 consisted of oil sales of $20.1 million, natural gas sales of $8.1 million and NGL sales of $3.4 million. Sales revenues for the three months ended March 31, 2013 consisted of oil sales of $15.5 million, natural gas sales of $6.1 million and NGL sales of $2.2 million.

Our production volumes for the three months ended March 31, 2014 included 303 MBbls of oil and NGLs and 1,622 MMcf of natural gas, or 3,367 Bbl/d of oil and NGLs and 18,022 Mcf/d of natural gas. On an equivalent basis, production for the period was 573 MBoe, or 6,367 Boe/d. Our average net production for the three months ended March 31, 2014 was negatively impacted by flaring at the Red Lake field of approximately 75 Boe/d and by the winter storms and other delays of approximately 100 Boe/d. Our production volumes for the three months ended March 31, 2013 included 260 MBbls of oil and NGLs and 1,808 MMcf of natural gas, or 2,889 Bbl/d of oil and NGLs and 20,089 Mcf/d of natural gas. On an equivalent basis, production for the period was 561 MBoe, or 6,233 Boe/d.

Our average sales price per Bbl for oil and NGLs for the three months ended March 31, 2014, excluding the effect of commodity derivative contracts, was $92.46 and $39.58, respectively. Our average sales price per Mcf of natural gas for the three months ended March 31, 2014, excluding the effect of commodity derivative contracts, was $4.99. Our average sales price per Bbl for oil and NGLs for the three months ended March 31, 2013, excluding the effect of commodity derivative contracts, was $82.25 and $31.04, respectively. Our average sales price per Mcf of natural gas for the three months ended March 31, 2013, excluding the effect of commodity derivative contracts, was $3.36.

Effects of Commodity Derivative Contracts. Due to changes in oil and natural gas prices, we recorded a net loss from our commodity hedging program for the three months ended March 31, 2014 of approximately $5.6 million, which is comprised of positive settlements and amortization of purchases of approximately $0.4 million and declines in the fair value of derivatives of approximately $6.0 million. For the three months ended March 31, 2013, we recorded a net loss from our commodity hedging program of approximately $6.1 million, which is comprised of positive settlements and amortization of approximately $4.1 million and declines in fair value of derivatives of approximately $10.2 million. Volatility in commodity prices has had a significant impact on our gains and losses on commodity derivative contracts.

Lease Operating Expense. Our lease operating expenses were approximately $5.8 million, or $10.18 per Boe, for the three months ended March 31, 2014 compared to approximately $6.8 million, or $12.11 per Boe, for the three months ended March 31, 2013. The primary driver of the decreased lease operating expenses were lower workover expenses.

Production and Ad Valorem Taxes. Our production and ad valorem taxes were approximately $2.4 million, or $4.19 per Boe, for the three months ended March 31, 2014 compared to approximately $1.8 million, or $3.29 per Boe, for the three months ended March 31, 2013. Production taxes accounted for approximately $2.3 million and ad


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valorem taxes for $0.1 million of the total taxes recorded during the three months ended March 31, 2014. Production taxes accounted for approximately $1.6 million and ad valorem taxes for $0.2 million of the total taxes recorded during the three months ended March 31, 2013.

Depletion and Depreciation. Our depletion and depreciation expense was approximately $8.5 million, or $14.76 per Boe, for the three months ended March 31, 2014 compared to approximately $10.1 million, or $18.01 per Boe, for the three months ended March 31, 2013. The decrease in depletion and depreciation expense and per Boe amounts was primarily related to a higher reserve base and lower property and equipment balances as of March 31, 2014.

Impairment of Oil and Natural Gas Properties. We did not record an impairment charge in the three months ended March 31, 2014 and 2013. If future oil or natural gas prices or reserves decline, the estimated undiscounted future cash flows for our oil and natural gas properties may not exceed the net capitalized costs for such properties and a non-cash impairment charge may be required to be recognized in future periods. As of May 2, 2014, the NYMEX-WTI oil spot price was $99.76 per Bbl and the NYMEX-Henry Hub natural gas spot price was $4.72 per MMBtu.

General and Administrative Expenses. Our general and administrative expenses were approximately $3.2 million, or $5.55 per Boe, for the three months ended March 31, 2014 compared to approximately $3.4 million, or $6.11 per Boe, for the three months ended March 31, 2013.

Interest Expense. Our interest expense is comprised of interest on our credit facility and term loan and amortization of debt issuance costs. Interest expense was approximately $2.5 million and $2.3 million for the three months ended March 31, 2014 and 2013, respectively.

Effects of Interest Rate Derivatives. Loss on interest rate derivative contracts, net, was approximately $0.3 million for the three months ended March 31, 2014, including $0.2 million in negative settlements and $0.1 million in declines in fair value of the derivatives. Gain on interest rate derivative contracts, net, was approximately $0.1 million for the three months ended March 31, 2013, including $0.2 million in negative settlements and $0.3 million in positive fluctuations in fair value of the derivatives.

Non-GAAP Financial Measures

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

          Income tax expense (benefit);

          Interest expense-net, including (losses) gains on interest rate
derivative contracts, net;

          Depletion and depreciation;

          Accretion of asset retirement obligations;

          Amortization of equity awards;

          Loss (gain) on settlement of asset retirement obligations;

          Loss on commodity derivative instruments, net;

          Commodity derivative instrument settlements;

          Amortization of derivative contracts;

          Impairment of oil and natural gas properties; and

          Other non-recurring items that we deem appropriate.

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess our financial performance as compared to that of other companies and partnerships in our industry, without regard to financing methods, capital structure or historical cost basis.


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

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

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

Our Adjusted EBITDA for the three months ended March 31, 2014 and 2013 was approximately $21.0 million and $16.2 million, respectively. The increase was primarily driven by higher revenues and lower operating expenses.

Our Distributable Cash Flow for the three months ended March 31, 2014 and 2013 was approximately $13.4 million and $8.9 million, respectively. The increase in Distributable Cash Flow was driven by the increased Adjusted EBITDA as discussed above.

Reconciliation of Adjusted EBITDA and Distributable Cash Flow to Net Income



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



                                                      Three Months Ended March 31,
(in thousands)                                          2014               2013
Net income (loss)                                  $         2,694    $        (7,002 )
Income tax expense                                              74                  5
Interest expense-net, including (loss) gain on
interest rate derivative instruments                         2,835              2,150
Depletion and depreciation                                   8,465             10,110
Accretion of asset retirement obligations                      503                470
Amortization of equity awards                                  285                115
Loss (gain) on settlement of asset retirement
obligations                                                     40                (25 )
Loss on commodity derivative instruments, net                5,622              6,067
Commodity derivative instrument settlements                    366              4,105
Amortization of derivative contracts                           157                247
Impairment of oil and natural gas properties                     -                  -
Adjusted EBITDA                                    $        21,041    $        16,242


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                                              Three Months Ended March 31,
                                                 2014              2013
Adjusted EBITDA                                      21,041           16,242
Cash income tax expense                                 (44 )             (5 )
Cash interest expense, including
realized gains and losses                            (2,644 )         (2,302 )
Estimated maintenance capital (1)                    (5,000 )         (5,075 )

Distributable Cash Flow $ 13,353 $ 8,860



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

Liquidity and Capital Resources

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

Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our credit facility and term loan and equity offerings under our recently established "at-the-market" offering program (the "ATM Program"), described below. We may issue additional equity and debt as needed.

On February 4, 2014, we launched the ATM Program with MLV & Co. LLC ("MLV") as sales agent. We may sell from time to time through MLV our common units representing limited partner interests having an aggregate offering amount of up to $75,000,000. Any sales of common units under the ATM Program may be made by any method permitted by law deemed to be an "at-the-market offering" defined by Rule 415 of the Securities Act, including, without limitation, sales made directly on the New York Stock Exchange, on any other existing trading market for our common units or to or through a market maker. During the three months ended March 31, 2014, we received net proceeds from the sale of 261,426 newly issued common units of $4.2 million, after deducting underwriting discounts and commissions and offering expenses of $0.3 million , and used the proceeds for general partnership purposes. During the three months ended March 31, 2014, we paid approximately $0.1 million of aggregate compensation to MLV for sales under the ATM program.

Our second lien term loan requires that 50% of the net cash proceeds from any equity offering be used to repay borrowings outstanding under the term loan. On February 12, 2014, we entered into an amendment to our term loan to waive this requirement through June 30, 2014.

We enter into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy, we enter into commodity derivative contracts at times and on terms desired to maintain a . . .

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