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LGCY > SEC Filings for LGCY > Form 10-Q on 1-Aug-2014All Recent SEC Filings

Show all filings for LEGACY RESERVES LP

Form 10-Q for LEGACY RESERVES LP


1-Aug-2014

Quarterly Report


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

Cautionary Statement Regarding Forward-Looking Information

This document 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 strategy;

•the amount of oil and natural gas we produce;

•the price at which we are able to sell our oil and natural gas production;

•our ability to acquire additional oil and natural gas properties at economically attractive prices;

•our drilling locations and our ability to continue our development activities at economically attractive costs;

•            the level of our lease operating expenses, general and
             administrative costs and finding and development costs, including
             payments to our general partner;

•the level of capital expenditures;

•the level of cash distributions to our unitholders;

•our future operating results; and

•our plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this document, are forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as "may," "could," "should," "expect," "plan," "project," "intend," "anticipate," "believe," "estimate," "predict," "potential," "pursue," "target," "continue," the negative of such terms or other comparable terminology.

The forward-looking statements contained in this document are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management's assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this document are not guarantees of future performance, and our expectations may not be realized or the forward-looking events and circumstances may not occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in Legacy's Annual Report on Form 10-K for the year ended December 31, 2013 in Item 1A under "Risk Factors" and Legacy's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 in Part II, Item 1A under "Risk Factors." The forward-looking statements in this document speak only as of the date of this document; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly.

Overview

Because of our rapid growth through acquisitions and development of properties, historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful or indicative of future results.

Acquisitions have been financed with a combination of proceeds from bank borrowings, issuance of notes, issuances of units and preferred units and cash flow from operations. Post-acquisition activities are focused on evaluating and developing the acquired properties and evaluating potential add-on acquisitions. Our revenues, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future.

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Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital and the amount of our cash distributions.

We face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well or formation decreases. We attempt to overcome this natural decline by acquiring more reserves than we produce, drilling to find additional reserves, utilizing multiple types of recovery techniques such as secondary (waterflood) and tertiary (CO2 and nitrogen) recovery methods to re-pressure the reservoir and recover additional oil, recompleting or adding pay in existing wellbores and improving artificial lift. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on adding reserves through acquisitions and exploitation projects. Our ability to add reserves through acquisitions and development projects is dependent upon many factors including our ability to raise capital, competitively bid on acquisitions, obtain regulatory approvals and contract drilling rigs and personnel.

Our revenues are highly sensitive to changes in oil and natural gas prices and to levels of production. As set forth under "Investing Activities" below, we have entered into oil and natural gas derivatives designed to mitigate the effects of price fluctuations covering a significant portion of our expected production, which allows us to mitigate, but not eliminate, oil and natural gas price risk. We continuously conduct financial sensitivity analyses to assess the effect of changes in pricing and production. These analyses allow us to determine how changes in oil and natural gas prices will affect our ability to execute our capital investment programs and to meet future financial obligations. Further, the financial analyses allow us to monitor any impact such changes in oil and natural gas prices may have on the value of our proved reserves and their impact on any redetermination to our borrowing base under our revolving credit facility.

Legacy does not specifically designate derivative instruments as cash flow hedges; therefore, the mark-to-market adjustment reflecting the change in fair value associated with these instruments is recorded in current earnings.

Production and Operating Costs Reporting

We strive to increase our production levels to maximize our revenue and cash available for distribution. Additionally, we continuously monitor our operations to ensure that we are incurring operating costs at the optimal level. Accordingly, we continuously monitor our production and operating costs per well to determine if any wells or properties should be shut-in or recompleted.

Such costs include, but are not limited to, the cost of electricity to lift produced fluids, chemicals to treat wells, field personnel to monitor the wells, well repair expenses to restore production, well workover expenses intended to increase production, and ad valorem taxes. We incur and separately report severance taxes paid to the states in which our properties are located. These taxes are reported as production taxes and are a percentage of oil and natural gas revenue. Ad valorem taxes are a percentage of property valuation. Gathering and transportation costs are generally borne by the purchasers of our oil and natural gas as the price paid for our products reflects these costs. We do not consider royalties paid to mineral owners an expense as we deduct hydrocarbon volumes owned by mineral owners from the reported hydrocarbon sales volumes.

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Operating Data

The following table sets forth selected unaudited financial and operating data
of Legacy for the periods indicated.
                                            Three Months Ended             Six Months Ended
                                                 June 30,                      June 30,
                                            2014           2013           2014           2013
                                                  (In thousands, except per unit data)
Revenues:
Oil sales                               $  108,731     $   97,852     $  210,786     $  188,209
Natural gas liquids sales                    5,103          3,161          9,069          6,503
Natural gas sales                           23,280         17,373         43,163         32,553
Total revenue                           $  137,114     $  118,386     $  263,018     $  227,265
Expenses:
Oil and natural gas production,
excluding ad valorem taxes              $   42,056     $   34,265     $   81,694     $   66,650
Ad valorem taxes                        $    3,753     $    2,919     $    6,649     $    5,885
Total oil and natural gas production    $   45,809     $   37,184     $   88,343     $   72,535
Production and other taxes              $    8,595     $    6,771     $   16,550     $   13,698
General and administrative, excluding
LTIP                                    $   12,669     $    5,720     $   19,626     $   11,017
LTIP expense                            $    2,140     $    1,344     $    2,830     $    2,329
Total general and administrative        $   14,809     $    7,064     $   22,456     $   13,346
Depletion, depreciation,
amortization and accretion              $   38,537     $   39,113     $   72,234     $   80,765
Commodity derivative cash
settlements:
Oil derivative cash settlements paid    $   (6,244 )   $   (1,934 )   $   (8,800 )   $   (1,705 )
Natural gas derivative cash
settlements received (paid)             $      234     $      584     $     (820 )   $    2,990
Production:
Oil (MBbls)                                  1,175          1,089          2,310          2,203
Natural gas liquids (MGal)                   5,519          3,320          8,881          6,213
Natural gas (MMcf)                           4,877          3,649          8,102          7,194
Total (MBoe)                                 2,119          1,776          3,872          3,550
Average daily production (Boe/d)            23,286         19,516         21,392         19,613
Average sales price per unit
(excluding derivative cash
settlements):
Oil price (per Bbl)                     $    92.54     $    89.85     $    91.25     $    85.43
Natural gas liquids price (per Gal)     $     0.92     $     0.95     $     1.02     $     1.05
Natural gas price (per Mcf) (a)         $     4.77     $     4.76     $     5.33     $     4.53
Combined (per Boe)                      $    64.71     $    66.66     $    67.93     $    64.02
Average sales price per unit
(including derivative cash
settlements):
Oil price (per Bbl)                     $    87.22     $    88.08     $    87.44     $    84.66
Natural gas liquids price (per Gal)     $     0.92     $     0.95     $     1.02     $     1.05
Natural gas price (per Mcf) (a)         $     4.82     $     4.92     $     5.23     $     4.94
Combined (per Boe)                      $    61.87     $    65.90     $    65.44     $    64.38

Average WTI oil spot price (per Bbl)    $   103.35     $    94.05     $   101.05     $    94.18
Average Henry Hub natural gas index
price (per Mcf)                         $     4.68     $     3.34     $     4.81     $     3.72

Average unit costs per Boe:
Oil and natural gas production          $    19.85     $    19.29     $    21.10     $    18.77
Ad valorem taxes                        $     1.77     $     1.64     $     1.72     $     1.66
Production and other taxes              $     4.06     $     3.81     $     4.27     $     3.86
General and administrative excluding
LTIP                                    $     5.98     $     3.22     $     5.07     $     3.10
Total general and administrative        $     6.99     $     3.98     $     5.80     $     3.76
Depletion, depreciation, amortization
and accretion                           $    18.19     $    22.02     $    18.66     $    22.75



(a) We primarily report and account for our Permian Basin natural gas volumes inclusive of the NGL content contained within those natural gas volumes. Given the price disparity between an equivalent amount of NGLs compared to natural gas, our realized natural gas prices in the Permian Basin and for Legacy as a whole are higher than Henry Hub natural gas index prices due to this NGL content.

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Results of Operations

Three-Month Period Ended June 30, 2014 Compared to Three-Month Period Ended June 30, 2013

Our revenues from the sale of oil were $108.7 million and $97.9 million for the three-month periods ended June 30, 2014 and 2013, respectively. Our revenues from the sale of NGLs were $5.1 million and $3.2 million for the three-month periods ended June 30, 2014 and 2013, respectively. We had revenues from the sale of natural gas of $23.3 million and $17.4 million for the three-month periods ended June 30, 2014 and 2013, respectively. The $10.9 million increase in oil revenues reflects the increase in oil production of 86 MBbls (8%) as well as an increase in average realized price of $2.69 per Bbl (3%). This increase in production is related to our purchase of additional oil and natural gas properties during the second quarter of 2014, as well as our ongoing development activities. The improvement in realized oil prices of $2.69 per Bbl during the three months ended June 30, 2014 compared to the same period in 2013 was due to an improvement in average West Texas Intermediate ("WTI") crude oil prices of $9.30 per Bbl partially offset by an increase in realized regional differentials, which reduce the price we receive for our oil. The $1.9 million increase in NGL sales reflects an increase in NGL production of 2,199 MGals (66%), primarily due to the WPX Acquisition (1,896 MGals), partially offset by a decrease in the realized NGL price of approximately $0.03 (3%). The $5.9 million increase in natural gas revenues reflects an increase in our production volumes, partially offset by a decrease in realized natural gas prices. Our natural gas production increased by approximately 1,228 MMcf (34%) primarily due to the acquisition of a non-operated interest in oil and natural gas properties located in the Piceance Basin in Garfield County, Colorado from WPX Energy Rocky Mountain, LLC, a subsidiary of WPX Energy, Inc. (the "WPX Acquisition"), which accounted for approximately 1,469 MMcf, partially offset by ordinary natural gas decline. Average realized natural gas prices remained virtually flat, increasing by $0.01 per Mcf (0%) during the three months ended June 30, 2014 compared to the same period in 2013 due to the inclusion of natural gas from the WPX Acquisition, which receives a lower price than NYMEX Henry Hub pricing. We primarily report and account for our Permian Basin natural gas volumes inclusive of the NGL content contained within those natural gas volumes. Given the price disparity between an equivalent amount of NGLs compared to natural gas, our realized natural gas prices in the Permian Basin are higher than NYMEX Henry Hub natural gas prices due to this NGL content.

For the three-month period ended June 30, 2014, we recorded $31.4 million of net losses on oil and natural gas derivatives. Commodity derivative gains and losses represent the changes in fair value of our commodity derivatives during the period and are based on oil and natural gas futures prices. The net losses recognized during the three-month period ended June 30, 2014 are primarily due to the increase in oil prices during the period. For the three-month period ended June 30, 2013, we recorded $25.3 million of net gains on oil and natural gas derivatives. Settlements of such contracts resulted in cash payments of $6.0 million and $1.4 million during the three months ended June 30, 2014 and 2013, respectively.

Our oil and natural gas production expenses, excluding ad valorem taxes, increased to $42.1 million ($19.85 per Boe) for the three-month period ended June 30, 2014 from $34.3 million ($19.29 per Boe) for the three-month period ended June 30, 2013. Production expenses increased primarily due to expenses associated with our acquisitions including $2.1 million related to the WPX Acquisition as well as development activities and, to a lesser extent, industry-wide cost increases. Our ad valorem tax expense increased marginally to $3.8 million ($1.77 per Boe) for the three-month period ended June 30, 2014 compared to $2.9 million ($1.64 per Boe) for the three-month period ended June 30, 2013 primarily due to increased well counts from recent acquisitions.

Our production and other taxes were $8.6 million and $6.8 million for the three-month periods ended June 30, 2014 and 2013, respectively. Production and other taxes increased because of increased production volumes related to recent acquisitions and increased product prices, as production and other taxes as a percentage of revenue remained relatively unchanged during the three-month period ended June 30, 2014 compared to the same period in 2013.

Our general and administrative expenses were $14.8 million and $7.1 million for the three-month periods ended June 30, 2014 and 2013, respectively. General and administrative expenses increased $7.7 million primarily due $4.9 million of acquisition-related expenses, a $1.7 million increase in salary and benefit expenses related to the hiring of additional personnel to manage our larger asset base and a $0.8 million increase in LTIP expenses due to the increase in unit price during the period.

We incurred depletion, depreciation, amortization and accretion expense, or DD&A, of $38.5 million and $39.1 million for the three-month periods ended June 30, 2014 and 2013, respectively. DD&A decreased due to a decrease in both the depletion rate and depletable basis due to prior year depletion and impairment which reduced the amount available to be depleted. This reduction was partially offset by the WPX Acquisition and other recent acquisitions. As the depletion rate is a function of production and reserves, the increase in our reserves balance due to the WPX Acquisition and other recent acquisitions, combined with only a partial quarter of increased production from the acquisitions, resulted in a lower depletion rate.

Page 33

Impairment expense was $2.4 million and $20.8 million for the three-month periods ended June 30, 2014 and 2013, respectively. In the three-month period ended June 30, 2014, we recognized $2.4 million of impairment expense on two separate producing fields primarily related to the removal of a proved undeveloped drilling ("PUD") location from a field as recent results from offset developments operated by other producers reduced the viability of development. The removal of this PUD reduced the expected cash flows for this field, resulting in impairment. Impairment expense for the period ended June 30, 2013 was primarily related to higher realized oil and natural gas differentials, which reduced the future expected cash flows.

We recorded interest expense of $16.2 million and $11.2 million for the three-month periods ended June 30, 2014 and 2013, respectively. Interest expense increased approximately $5.0 million primarily due to interest expense related to additional senior notes issued subsequent to June 30, 2013.

Six-Month Period Ended June 30, 2014 Compared to Six-Month Period Ended June 30, 2013

Our revenues from the sale of oil were $210.8 million and $188.2 million for the six-month periods ended June 30, 2014 and 2013, respectively. Our revenues from the sale of NGLs were $9.1 million and $6.5 million for the six-month periods ended June 30, 2014 and 2013, respectively. We had revenues from the sale of natural gas of $43.2 million and $32.6 million for the six-month periods ended June 30, 2014 and 2013, respectively. The $22.6 million increase in oil revenues reflects the increase in oil production of 107 MBbls (5%) as well as an increase in average realized price of $5.82 per Bbl (7%). This increase in production is related to our purchase of additional oil and natural gas properties in recent acquisitions, as well as our ongoing development activities partially offset by a decline in the Lower Abo oil production and downtime related to inclement weather. The improvement in realized oil prices of $5.82 per Bbl during the six months ended June 30, 2014 compared to the same period in 2013 was due to an improvement in average West Texas Intermediate ("WTI") crude oil prices of $6.87 per Bbl partially offset by increased regional crude oil differentials. The $2.6 million increase in NGL sales reflects an increase in NGL production of 2,668 MGals (43%), primarily due to the WPX Acquisition (1,896 MGals), partially offset by a reduction in realized NGL price of approximately $0.03 (3%). The $10.6 million increase in natural gas revenues reflects an increase in our production volumes as well as an increase in realized natural gas prices. Our natural gas production increased by approximately 908 MMcf (13%) primarily due to the WPX Acquisition (1,469 MMcf) partially offset by declines related to our Lower Abo properties as well as plant and gathering downtime related to inclement weather as well as other gathering issues which reduced the volumes available for sale. Average realized natural gas prices increased by $0.80 per Mcf (18%) during the six months ended June 30, 2014 compared to the same period in 2013, primarily due to the increase in index prices. We primarily report and account for our Permian Basin natural gas volumes inclusive of the NGL content contained within those natural gas volumes. Given the price disparity between an equivalent amount of NGLs compared to natural gas, our realized natural gas prices in the Permian Basin are higher than NYMEX Henry Hub natural gas prices due to this NGL content.

For the six-month period ended June 30, 2014, we recorded $47.3 million of net losses on oil and natural gas derivatives. Commodity derivative gains and losses represent the changes in fair value of our commodity derivatives during the period and are based on oil and natural gas futures prices. The net losses recognized during the six-month period ended June 30, 2014 are primarily due to the increase in oil prices during the period. For the six-month period ended June 30, 2013, we recorded $12.3 million of net gains on oil and natural gas derivatives. Settlements of such contracts resulted in cash payments of $9.6 million and cash receipts of $1.3 million during the six months ended June 30, 2014 and 2013, respectively.

Our oil and natural gas production expenses, excluding ad valorem taxes, increased to $81.7 million ($21.10 per Boe) for the six-month period ended June 30, 2014 from $66.7 million ($18.77 per Boe) for the six-month period ended June 30, 2013. Production expenses increased primarily due to expenses associated with our acquisitions and development activities as well as a $3.5 million increase in one-time well workover expenses and industry-wide cost increases. Our ad valorem tax expense increased marginally to $6.6 million ($1.72 per Boe) for the six-month period ended June 30, 2014 compared to $5.9 million ($1.66 per Boe) for the six-month period ended June 30, 2013 primarily due to increased well counts from recent acquisitions.

Our production and other taxes were $16.6 million and $13.7 million for the six-month periods ended June 30, 2014 and 2013, respectively. Production and other taxes increased because of increased production volumes related to recent acquisitions and increased product prices, as production and other taxes as a percentage of revenue remained relatively unchanged during the six-month period ended June 30, 2014 compared to the same period in 2013.

Our general and administrative expenses were $22.5 million and $13.3 million for the six-month periods ended June 30, 2014 and 2013, respectively. General and administrative expenses increased $9.1 million primarily due to $4.9 million of acquisition-related expenses, a $3.2 million increase in salary and benefit expenses related to the hiring of additional personnel to manage our larger asset base and a $0.5 million increase in LTIP expenses due to the increase in unit price during the period.

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We incurred depletion, depreciation, amortization and accretion expense, or DD&A, of $72.2 million and $80.8 million for the six-month periods ended June 30, 2014 and 2013, respectively. DD&A decreased due to a decrease in both the depletion rate and depletable basis due to prior year depletion and impairment which reduced the amount available to be depleted. This reduction was partially offset by the WPX Acquisition and other recent acquisitions. As the depletion rate is a function of production and reserves, the increase in our reserves balance due to the WPX Acquisition and other recent acquisitions, combined with only a partial quarter of increased production from the acquisitions, resulted in a lower depletion rate.

Impairment expense was $3.8 million and $22.5 million for the six-month periods ended June 30, 2014 and 2013, respectively. In the six-month period ended June 30, 2014, we recognized $3.8 million of impairment expense on four separate producing fields primarily related to a reduction in the future expected cash flows from four unproved properties and the removal of a PUD. We consider expected cash flows from both proved and unproved properties in a given field when reviewing for impairment. In the case of two of the impaired fields, impairment was indicated in previous periods, but the additional cash flow from identified unproved projects mitigated the indicated impairment. During the six months ended June 30, 2014, we revised certain reserve estimates associated with these unproved properties due to other operators' recent drilling results on adjacent properties and thus recognized impairment on the reduced expected cash flows. Impairment expense for the period ended June 30, 2013 was primarily related to higher realized oil and natural gas differentials, which reduced the future expected cash flows.

We recorded interest expense of $30.2 million and $21.9 million for the six-month periods ended June 30, 2014 and 2013, respectively. Interest expense increased approximately $8.3 million primarily due to interest expense related to additional senior notes issued subsequent to June 30, 2013.

Non-GAAP Financial Measure

Our management uses Adjusted EBITDA as a tool to provide additional information and metrics relative to the performance of our business. Our management believes that Adjusted EBITDA is useful to investors because this measure is used by many companies in the industry as a measure of operating and financial performance and is 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 may not be comparable to a similarly titled measure of other publicly traded limited partnerships or limited liability companies because all companies may not calculate Adjusted EBITDA in the same manner.

The following presents a reconciliation of "Adjusted EBITDA," which is a non-GAAP measure, to its nearest comparable GAAP measure. Adjusted EBITDA should not be considered as an alternative to GAAP measures, such as net income, operating income, cash flow from operating activities, or any other GAAP measure of financial performance.

Adjusted EBITDA is defined as net income (loss) plus:
• Interest expense;

• Income taxes;

• Depletion, depreciation, amortization and accretion;

• Impairment of long-lived assets;

• (Gain) loss on sale of partnership investment;

. . .

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