Search the web
Welcome, Guest
[Sign Out, My Account]
EDGAR_Online

Quotes & Info
Enter Symbol(s):
e.g. YHOO, ^DJI
Symbol Lookup | Financial Search
LRE > SEC Filings for LRE > Form 10-Q on 7-Aug-2013All Recent SEC Filings

Show all filings for LRR ENERGY, L.P.

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


7-Aug-2013

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, 2012 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 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 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


Table of Contents

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

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

Overview

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

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 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 Note 2 of our Annual Report on Form 10-K for the year ended December 31, 2012 (the "2012 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 since November 16, 2011.


Table of Contents

                                            Three Months Ended June 30,        Six Months Ended June 30,
                                               2013              2012            2013             2012
Revenues (in thousands):
Oil sales                                 $       19,012    $       18,709   $      34,475    $      37,188
Natural gas sales                                  7,720             4,827          13,800           10,810
Natural gas liquids sales                          2,275             2,955           4,510            6,186
Realized gain on commodity derivative
instruments                                        2,143             6,820           6,248           12,068
Unrealized gain on commodity Derivative
instruments                                       10,211            12,953              39           12,365
Other income                                          18                 -              87                3
Total revenues                                    41,379            46,264          59,159           78,620

Expenses (in thousands):
Lease operating expense                            5,270             8,003          12,067           15,071
Production and ad valorem taxes                    2,198             1,929           4,044            3,800
Depletion and depreciation                        10,129            12,011          20,239           22,627
Impairment of oil and natural gas
properties                                             -                 -               -            3,093
General and administrative expense                 2,768             3,450           6,197            6,745
Interest expense                                   2,249             1,332           4,514            2,460
Realized loss on interest rate
derivative instruments                               178               108             352              141
Unrealized (gain) loss on interest rate
derivative instruments                            (2,835 )           2,852          (3,124 )          2,047

Production:
Oil (MBbls)                                          210               218             398              407
Natural gas (MMcf)                                 1,843             2,161           3,651            4,347
NGLs (MBbls)                                          73                76             145              143
Total (MBoe)                                         590               654           1,152            1,275
Average net production (Boe/d)                     6,484             7,187           6,365            7,005

Average sales price:
Oil (per Bbl)
Sales price                               $        90.53    $        85.82   $       86.62    $       91.37
Effect of realized commodity derivative
instruments                                         0.39              5.12            0.80             2.64
Realized price                            $        90.92    $        90.94   $       87.42    $       94.01
Natural gas (per Mcf)
Sales price                               $         4.19    $         2.23   $        3.78    $        2.49
Effect of realized commodity derivative
instruments                                         0.87              2.42            1.41             2.42
Realized price                            $         5.06    $         4.65   $        5.19    $        4.91
NGLs (per Bbl)
Sales price                               $        31.16    $        38.88   $       31.10    $       43.26
Effect of realized commodity derivative
instruments                                         6.26              6.33            5.49             3.41
Realized price                            $        37.42    $        45.21   $       36.59    $       46.67

Average unit cost per Boe:
Lease operating expenses                  $         8.93    $        12.23   $       10.48    $       11.83
Production and ad valorem taxes                     3.72              2.95            3.51             2.98
Depletion and depreciation                         17.16             18.36           17.58            17.75
General and administrative expenses                 4.69              5.27            5.38             5.29

Our Results for the Three Months Ended June 30, 2013 Compared to the Three Months Ended June 30, 2012

We recorded net income of $20.5 million for the three months ended June 30, 2013 compared to net income of $16.2 million during the three months ended June 30, 2012, primarily related to higher sales revenues due to higher commodity prices and lower operating expense. The following discussion summarizes key components of the changes between periods.


Table of Contents

Sales Revenues. A summary of increases (decreases) in our oil, natural gas and NGL revenues between June 30, 2012 and June 30, 2013 follows (in thousands):

Oil, natural gas and NGL revenues-prior period     $  26,491
Increase (decrease)
Price realization
Oil                                                    1,027
Natural gas                                            4,225
NGLs                                                    (587 )
Sales volumes
Oil                                                     (724 )
Natural gas                                           (1,332 )
NGLs                                                     (93 )
Oil, natural gas and NGL revenues-current period   $  29,007

Sales revenues increased from $26.5 million for the three months ended June 30, 2012 to $29.0 million for the three months ended June 30, 2013, primarily due to higher natural gas and oil price realizations offset by lower natural gas sales volumes. Sales revenues for the three months ended June 30, 2013 consisted of oil sales of $19.0 million, natural gas sales of $7.7 million and NGL sales of $2.3 million. Sales revenues for the three months ended June 30, 2012 consisted of oil sales of $18.7 million, natural gas sales of $4.8 million and NGL sales of $3.0 million.

Our production volumes for the three months ended June 30, 2013 included 283 MBbls of oil and NGLs and 1,843 MMcf of natural gas, or 3,110 Bbl/d of oil and NGLs and 20,253 Mcf/d of natural gas. On an equivalent basis, production for the period was 590 MBoe, or 6,484 Boe/d. Our production volumes for the three months ended June 30, 2012 included 294 MBbls of oil and NGLs and 2,161 MMcf of natural gas, or 3,231 Bbl/d of oil and NGLs and 23,747 Mcf/d of natural gas. On an equivalent basis, production for the period was 654 MBoe, or 7,187 Boe/d.

At our Red Lake field, our third party gas processor required us to flare approximately 90 Boe/d due to third-party compression limits during the quarter. We are currently flaring approximately 90 Boe/d and we expect that we will continue to flare at this level until a new compressor station at the plant is put into service, which we expect will occur during the fourth quarter of 2013.

Our Pecos Slope field continued to be curtailed by approximately 1.0 MMcf/d (167 Boe/d) during the quarter due the previously disclosed high nitrogen content of our produced natural gas. We expect the curtailment to remain at this level until the field-wide nitrogen rejection facility is installed, which we expect will occur in late 2013.

Our average sales price per Bbl for oil and NGLs for the three months ended June 30, 2013, excluding the effect of commodity derivative contracts, was $90.53 and $31.16, respectively. Our average sales price per Mcf of natural gas for the three months ended June 30, 2013, excluding the effect of commodity derivative contracts, was $4.19. Our average sales price per Bbl for oil and NGLs for the three months ended June 30, 2012, excluding the effect of commodity derivative contracts, was $85.82 and $38.88, respectively. Our average sales price per Mcf of natural gas for the three months ended June 30, 2012, excluding the effect of commodity derivative contracts, was $2.23.

Effects of Commodity Derivative Contracts. Due to changes in oil and natural gas prices, we recorded a net gain from our commodity hedging program for the three months ended June 30, 2013 of approximately $12.3 million, which is comprised of a realized gain of approximately $2.1 million and an unrealized gain of approximately $10.2 million. For the three months ended June 30, 2012, we recorded a net gain from our commodity hedging program of approximately $19.8 million, which is comprised of a realized gain of approximately $6.8 million and an unrealized gain of approximately $13.0 million. Volatility in commodity prices has had a significant impact on our realized and unrealized gains and losses on commodity derivative contracts.

Lease Operating Expenses. Our lease operating expenses were approximately $5.3 million, or $8.93 per Boe, for the three months ended June 30, 2013 compared to approximately $8.0 million, or $12.23 per Boe, for the three months ended June 30, 2012. The primary drivers of the decreased lease operating expenses were lower workover expenses and lower saltwater disposal costs.


Table of Contents

Production and Ad Valorem Taxes. Our production and ad valorem taxes were approximately $2.2 million, or $3.72 per Boe, for the three months ended June 30, 2013 compared to approximately $1.9 million, or $2.95 per Boe, for the three months ended June 30, 2012. Production taxes accounted for approximately $2.0 million and ad valorem taxes for $0.2 million of the total taxes recorded during the three months ended June 30, 2013. Production taxes accounted for approximately $1.7 million and ad valorem taxes for $0.2 million of the total taxes recorded during the three months ended June 30, 2012. The increase in the per Boe amounts were primarily related to lower production volumes.

Depletion and Depreciation. Our depletion and depreciation expense was approximately $10.1 million, or $17.16 per Boe, for the three months ended June 30, 2013 compared to approximately $12.0 million, or $18.36 per Boe, for the three months ended June 30, 2012. The decrease in the depreciation expense and per Boe amounts were primarily related to lower production volumes.

Impairment of Oil and Natural Gas Properties. We did not record an impairment charge in the three months ended June 30, 2013 and 2012. If future oil or natural gas prices decline, the estimated undiscounted future cash flows for our proved 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 August 2, 2013, the NYMEX-WTI oil spot price was $106.94 per Bbl and the NYMEX-Henry Hub natural gas spot price was $3.39 per MMBtu.

General and Administration Expenses. Our general and administrative expenses were approximately $2.8 million, or $4.69 per Boe, for the three months ended June 30, 2013 compared to approximately $3.5 million, or $5.27 per Boe, for the three months ended June 30, 2012. The decrease in general and administrative expenses was primarily due to costs incurred in connection with a drop-down transaction in the second quarter of 2012.

Interest Expenses. Our interest expense is comprised of interest on our credit facility and term loan, amortization of debt issuance costs and realized gains (losses) on our interest rate derivative instruments. Interest expense was approximately $2.4 million and $1.4 million for the three months ended June 30, 2013 and 2012, respectively. The increase in interest expense was primarily due to the increased debt level outstanding during the three months ended June 30, 2013. Unrealized gain on interest rate derivative contracts was approximately $2.8 million for the three months ended June 30, 2013, and unrealized loss on interest rate derivative contracts was approximately $2.9 million for the three months ended June 30, 2012.

Our Results for the Six Months Ended June 30, 2013 Compared to the Six Months Ended June 30, 2012

We recorded net income of $13.5 million for the six months ended June 30, 2013 compared to net income of $21.8 million during the six months ended June 30, 2012, primarily related to lower overall revenues and expenses. The following discussion summarizes key components of the changes between periods.

Sales Revenues. A summary of increases (decreases) in our oil, natural gas and NGL revenues between the six months ended June 30, 2012 and June 30, 2013 follows (in thousands):

Oil, natural gas and NGL revenues-prior period     $ 54,184
Increase (decrease)
Price realization
Oil                                                  (1,933 )
Natural gas                                           5,622
NGLs                                                 (1,739 )
Sales volumes
Oil                                                    (780 )
Natural gas                                          (2,631 )
NGLs                                                     62
Oil, natural gas and NGL revenues-current period   $ 52,785

Sales revenues decreased from $54.2 million for the six months ended June 30, 2012 to $52.8 million for the six months ended June 30, 2013, primarily driven by lower oil and NGL price realizations and decreased oil and natural


Table of Contents

gas production offset by higher natural gas price realizations. Sales revenues for the six months ended June 30, 2013 consisted of oil sales of $34.5 million, natural gas sales of $13.8 million and NGL sales of $4.5 million. Sales revenues for the six months ended June 30, 2012 consisted of oil sales of $37.2 million, natural gas sales of $10.8 million and NGL sales of $6.2 million.

Our production volumes for the six months ended June 30, 2013 included 543 MBbls of oil and NGLs and 3,651 MMcf of natural gas, or 3,000 Bbl/d of oil and NGLs and 20,171 Mcf/d of natural gas. On an equivalent basis, production for the period was 1,152 MBoe, or 6,365 Boe/d. Our production volumes for the six months ended June 30, 2012 included 550 MBbls of oil and NGLs and 4,347 MMcf of natural gas, or 3,022 Bbl/d of oil and NGLs and 23,885 Mcf/d of natural gas. On an equivalent basis, production for the period was 1,275 MBoe, or 7,005 Boe/d.

Our average daily production of 6,365 Boe/d for the six months ended June 30, 2013 was negatively impacted by the following items which resulted in lower production of approximately 380 Boe/d. The actual timing and amount of resumed production related to the items below may differ from these estimates.

At our Red Lake field, our third party gas processor required us to flare approximately 80 Boe/d due to plant capacity constraints and compressor issues during the six months ended June 30, 2013. We are currently flaring approximately 90 Boe/d due to third-party plant compression limits and we expect that we will continue to flare at this level until a new compressor station at the plant is put into service, which we expect will occur during the fourth quarter of 2013. Delays in our recompletion program at our Red Lake field during the first quarter resulted in lower production of approximately 21 Boe/d. The delayed projects were completed during the second quarter of 2013.

Production at our Putnam field experienced weather related shut-ins of approximately 33 Boe/d during the first quarter of 2013. The Putnam field resumed normal operations in the second quarter of 2013.

Our Pecos Slope field was curtailed by approximately 1.4 MMcf/d (233 Boe/d) during the six months ended June 30, 2013 due to the previously disclosed high nitrogen content of our produced natural gas (1.0 MMcf/d or 167 Boe/d) and a compressor failure (0.4 MMcf/d or 66 Boe/d). The compressor resumed service on February 18, 2013. The current nitrogen content curtailment is approximately 1.0 MMcf/d (167 Boe/d) and we expect it to remain at this level until the field-wide nitrogen rejection facility is installed, which we expect will occur in late 2013. A well at our New Years Ridge field had a tubing failure during the first quarter of 2013 resulting in curtailed production of approximately 75 Mcfe/d (12 Boe/d) during the six months ended June 30, 2013. The well resumed service during the second quarter of 2013.

Our average sales price per Bbl for oil and NGLs for the six months ended June 30, 2013, excluding the effect of commodity derivative contracts, was $86.62 and $31.10, respectively. Our average sales price per Mcf of natural gas for the six months ended June 30, 2013, excluding the effect of commodity derivative contracts, was $3.78. Our average sales price per Bbl for oil and NGLs for the six months ended June 30, 2012, excluding the effect of commodity derivative contracts, was $91.37 and $43.26, respectively. Our average sales price per Mcf of natural gas for the six months ended June 30, 2012, excluding the effect of commodity derivative contracts, was $2.49.

In addition to lower realized production, our financial results for the six months ended June 30, 2013 were impacted by a higher Midland to Cushing oil differential during the first quarter of 2013. The differential averaged $7.88 per barrel for the first quarter compared to the full year 2011 and 2012 average differential of $2.30 per barrel. We estimated the impact of the higher differential (compared to the 2011 and 2012 average differential) on revenue for the first quarter of 2013 was approximately $0.8 million. In February 2013, we executed Midland to Cushing oil basis swaps for March 2013 through December 2014 on the majority of our expected production that we expected to be impacted by the differential.

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 six months ended June 30, 2013 of approximately $6.3 million, which is comprised of a realized gain of approximately $6.3 million and an unrealized gain of less than $0.1 million. For the six months ended June 30, 2012, we recorded a net gain from our commodity hedging program of approximately $24.4 million, which is comprised of a realized gain of approximately $12.1 million and an unrealized gain of approximately $12.3 million. Volatility in commodity prices has had a significant impact on our realized and unrealized gains and losses on commodity derivative contracts.


Table of Contents

Lease Operating Expenses. Our lease operating expenses were approximately $12.1 million, or $10.48 per Boe, for the six months ended June 30, 2013 compared to approximately $15.1 million, or $11.83 per Boe, for the six months ended June 30, 2012. The primary drivers of the decreased lease operating expenses were lower workover expenses and lower saltwater disposal costs.

Production and Ad Valorem Taxes. Our production and ad valorem taxes were approximately $4.0 million, or $3.51 per Boe, for the six months ended June 30, 2013 compared to approximately $3.8 million, or $2.98 per Boe, for the six months ended June 30, 2012. Production taxes accounted for approximately $3.6 million and ad valorem taxes for $0.4 million of the total taxes recorded during the six months ended June 30, 2013. Production taxes accounted for approximately $3.5 million and ad valorem taxes for $0.3 million of the total taxes recorded during the six months ended June 30, 2012.

Depletion and Depreciation. Our depletion and depreciation expense was approximately $20.2 million, or $17.58 per Boe, for the six months ended June 30, 2013 compared to approximately $22.6 million, or $17.75 per Boe, for the six months ended June 30, 2012.

. . .

  Add LRE to Portfolio     Set Alert         Email to a Friend  
Get SEC Filings for Another Symbol: Symbol Lookup
Quotes & Info for LRE - All Recent SEC Filings
Copyright © 2014 Yahoo! Inc. All rights reserved. Privacy Policy - Terms of Service
SEC Filing data and information provided by EDGAR Online, Inc. (1-800-416-6651). All information provided "as is" for informational purposes only, not intended for trading purposes or advice. Neither Yahoo! nor any of independent providers is liable for any informational errors, incompleteness, or delays, or for any actions taken in reliance on information contained herein. By accessing the Yahoo! site, you agree not to redistribute the information found therein.