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LGCY > SEC Filings for LGCY > Form 10-K on 21-Feb-2014All Recent SEC Filings

Show all filings for LEGACY RESERVES LP

Form 10-K for LEGACY RESERVES LP


21-Feb-2014

Annual Report


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the "Selected Historical Consolidated Financial Data" and the accompanying financial statements and related notes included elsewhere in this annual report on Form 10-K. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this report, particularly in "Risk Factors" and "Cautionary Statement Regarding Forward-Looking Information," all of which are difficult to predict. In light of these risks, uncertainties and assumptions, actual results may differ materially from those anticipated or implied in the forward-looking statements.

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. The operating results of the acquisition of certain oil and natural gas properties located primarily in the Permian Basin from a subsidiary of Concho Resources, Inc (the "COG 2012 Acquisition") have been included since December 20, 2012. During 2013, we consummated $108.4 million of acquisitions, excluding $11.0 million of non-cash asset retirement obligations, consisting of 16 individually immaterial transactions. The operating results of these acquisitions have been included from their respective acquisition dates.


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Trends Affecting Our Business and Operations

Acquisitions have been financed with a combination of proceeds from bank borrowings, issuance of notes, issuances of units and cash flow from operations. Post-acquisition activities are focused on evaluating and exploiting 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.

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.

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 development projects. Our ability to add reserves through acquisitions and development projects is dependent upon many factors including our ability to raise capital, 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," we have entered into oil, NGL 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, NGL 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.

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 and counties 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 reported hydrocarbon sales volumes.


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Operating Data
The following table sets forth our selected financial and operating data for the
periods indicated.
                                                                    Year Ended December 31,
                                                             2013              2012(b)          2011
                                                            (In thousands, except per unit data and
                                                                          production)
Revenues
Oil sales                                              $     405,536       $     286,254     $ 264,473
Natural gas liquids sales                                     14,095              14,592        18,888
Natural gas sales                                             65,858              45,614        53,524
Total revenues                                         $     485,489       $     346,460     $ 336,885
Expenses:
Oil and natural gas production                         $     142,798       $     103,409     $  87,626
Ad valorem taxes                                              11,881               9,542         9,288
Total                                                  $     154,679       $     112,951     $  96,914
Production and other taxes                             $      29,508       $      20,778     $  20,329
General and administrative excluding LTIP              $      24,093       $      20,980     $  19,063
LTIP expense                                                   4,814               3,546         4,021
Total general and administrative                       $      28,907       $      24,526     $  23,084
Depletion, depreciation, amortization and accretion    $     158,415       $     102,144     $  88,178
Commodity derivative cash settlements:
Oil derivative cash settlements paid                         (14,160 )           (10,211 )     (11,335 )
Natural gas derivative cash settlements received               7,104              16,113        11,972
Total commodity derivative cash settlements                   (7,056 )             5,902           637
Production:
Oil (MBbls)                                                    4,475               3,337         2,951
Natural gas liquids (MGal)                                    13,272              14,607        14,559
Natural gas (MMcf)                                            14,328              10,417         8,842
Total (MBoe)                                                   7,179               5,421         4,771
Average daily production (Boe/d)                              19,668              14,811        13,071
Average sales price per unit (excluding commodity
derivative cash settlements):
Oil price (per Bbl)                                    $       90.62       $       85.78     $   89.62
Natural gas liquids price (per Gal)                    $        1.06       $        1.00     $    1.30
Natural gas price (per Mcf)(a)                         $        4.60       $        4.38     $    6.05
Combined (per Boe)                                     $       67.63       $       63.91     $   70.61
Average sales price per unit (including commodity
derivative cash settlements):
Oil price (per Bbl)                                    $       87.46       $       82.72     $   85.78
Natural gas liquids price (per Gal)                    $        1.06       $        1.00     $    1.30
Natural gas price (per Mcf)(a)                         $        5.09       $        5.93     $    7.41
Combined (per Boe)                                     $       66.64       $       65.00     $   70.74

Average WTI oil spot price (per Bbl)                   $       97.98       $       94.05     $   94.88
Average Henry Hub natural gas index price (per Mcf)    $        3.66       $        2.79     $    4.04

Average unit costs per Boe:
Production costs, excluding production and other taxes $       19.89       $       19.08     $   18.37
Ad valorem taxes                                       $        1.65       $        1.76     $    1.95
Production and other taxes                             $        4.11       $        3.83     $    4.26
General and administrative excluding LTIP              $        3.36       $        3.87     $    4.00
Total general and administrative                       $        4.03       $        4.52     $    4.84
Depletion, depreciation, amortization and accretion    $       22.07       $       18.84     $   18.48


____________________


(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.

(b) Reflects the production and operating results of the oil and natural gas properties acquired in the COG 2012 Acquisition from the closing date of the acquisition through December 31, 2012.


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Results of Operations

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Legacy's revenues from the sale of oil were $405.5 million and $286.3 million for the years ended December 31, 2013 and 2012, respectively. Legacy's revenues from the sale of NGLs were $14.1 million and $14.6 million for the years ended December 31, 2013 and 2012, respectively. Legacy's revenues from the sale of natural gas were $65.9 million and $45.6 million for the years ended December 31, 2013 and 2012, respectively. The $119.3 million increase in oil revenue reflects an increase in oil production of 1,138 MBbls (34%) combined with an increase in average realized price of $4.84 per Bbl (6%) to $90.62 for the year ended December 31, 2013 from $85.78 for the year ended December 31, 2012. The increase in production is due primarily to 1,005 MBbls of oil production related to Legacy's purchase of oil and natural gas properties in the COG 2012 Acquisition, and, to a lesser extent, production from our other acquisitions of additional oil and natural gas properties and our development activities that were primarily focused on oil-weighted projects in the Permian Basin. The increase in realized oil price was primarily caused by an increase in the average WTI crude oil price of $3.93, and to a lesser extent, improvements in our crude oil differentials in the Rocky Mountain and Permian Basin regions during the year ended December 31, 2013 compared to the same period in 2012. The $0.5 million decrease in NGL revenues reflects a decrease in NGL production of 1,335 MGal (9%) during 2013, partially offset by an increase in realized NGL price of $0.06 per Gal (6%) to $1.06 per Gal for the year ended December 31, 2013 from $1.00 per Gal for the year ended December 31, 2012. The $20.2 million increase in natural gas revenues reflects an increase in our natural gas production volumes combined with an increase in our realized natural gas prices. Our natural gas production increased by approximately 3,911 MMcf (38%), primarily due to our acquisitions, most notably the COG 2012 Acquisition (4,650 MMcf), as well as our development activities, which were partially offset by third party infrastructure issues that adversely impacted our natural gas production mostly in the Permian Basin during 2013. Average realized gas prices increased by $0.22 per Mcf (5%) to $4.60 per Mcf for the year ended December 31, 2013 from $4.38 per Mcf for the year ended December 31, 2012, as a significant increase in dry natural gas prices was mostly offset by a worsening of differentials primarily due to the curtailment of a portion of our NGL-rich natural gas production in the Permian Basin in 2013.

For the year ended December 31, 2013, Legacy recorded $13.5 million of net losses on oil and natural gas derivatives. Commodity derivative gains and losses represent the changes in fair value of our commodity derivative contracts during the period and are primarily based on oil and natural gas futures prices. The net loss recognized during 2013 was primarily due to increased oil futures prices for 2013 and 2014 and, to a lesser extent, higher natural gas futures prices partially offset by the impact of lower oil futures prices beyond 2014. For the year ended December 31, 2012, Legacy recorded $38.5 million of net gains on oil and natural gas derivatives. Settlements of such contracts resulted in cash payments of $7.1 million and cash receipts of $5.9 million during 2013 and 2012, respectively.

Legacy's oil and natural gas production expenses, excluding ad valorem taxes, increased to $142.8 million ($19.89 per Boe) for the year ended December 31, 2013 from $103.4 million ($19.08 per Boe) for the year ended December 31, 2012. Production expenses increased primarily due to $30.8 million of expenses related to properties acquired in the COG 2012 Acquisition, the acquisition of other oil and natural gas properties and, to a lesser extent, expenses associated with Legacy's development activities. Additionally, production expenses per Boe increased in 2013 compared to 2012 due to industry-wide cost increases and third-party infrastructure issues that negatively impacted our production for the period. Legacy's ad valorem tax expense increased to $11.9 million ($1.65 per Boe) for the year ended December 31, 2013 from $9.5 million ($1.76 per Boe) for the year ended December 31, 2012 due to increased well counts acquired in connection with the COG 2012 Acquisition and the acquisition of additional oil and natural gas properties.

Legacy's production and other taxes were $29.5 million and $20.8 million for the years ended December 31, 2013 and 2012, respectively. Production and other taxes increased because of higher total revenues in 2013, as production and other taxes are assessed as a percentage of revenue and that percentage remained relatively unchanged between 2013 and 2012.


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Legacy's general and administrative expenses were $28.9 million and $24.5 million for the years ended December 31, 2013 and 2012, respectively. General and administrative expenses increased approximately $4.4 million between periods primarily due to $2.9 million of increased salary and benefit expenses, net of overhead recovery, due to the hiring of additional personnel commensurate with the growth of our asset base and $1.3 million of increased unit-based compensation due to an increase in our unit price between December 31, 2012 and December 31, 2013.

Legacy's depletion, depreciation, amortization and accretion expense, or DD&A, was $158.4 million and $102.1 million for the years ended December 31, 2013 and 2012, respectively. DD&A increased primarily due to approximately $48.6 million of depletion expense related to the properties acquired in the COG 2012 Acquisition and development activity during the year ended December 31, 2013. Our depletion rate per Boe for the year ended December 31, 2013 was $22.07 compared to $18.84 for the year ended December 31, 2012. This increase is primarily driven by the COG 2012 Acquisition and other recent acquisitions, which have a higher costs basis than our historical assets.

Impairment expense was $85.8 million and $37.1 million for the years ended December 31, 2013 and 2012, respectively. In 2013, Legacy recognized $78.0 million of impairment expense in 98 separate producing fields, due primarily to the decrease in commodity prices primarily related to natural gas differentials during the year ended December 31, 2013, combined with higher lifting costs, which decreased the expected future cash flows below the carrying value of the assets. The remaining $7.8 million was impairment of unproved properties acquired since 2010 that are no longer viable. In 2012, Legacy recognized impairment expense of $22.8 million in 64 separate producing fields due primarily to the decrease in commodity prices during the year ended December 31, 2012 combined with higher lifting costs, which decreased the expected future cash flows below the carrying value of the assets. In 2012, Legacy also recognized $6.5 million of impairment related to the reduction in the carrying value of a property that Legacy entered into an option to sell. Finally, Legacy recognized $7.8 million of impairment of goodwill during 2012 related to a decline in oil futures prices between announcement and closing date of a transaction, as hedging does not impact the associated fair value of properties for purposes of measuring impairment.

Interest expense was $50.1 million and $20.3 million for the years ended December 31, 2013 and 2012, respectively. The increase in interest expense is primarily due to $35.1 million of interest expense related to the issuance of the Senior Notes in December 2012 and May 2013. This increase was partially offset by reduced interest rate expenses related to our interest rate swaps, which decreased by $3.3 million to $1.2 million in 2013 from $4.5 million in 2012. Cash payments on our interest rate swaps were $6.0 million and $7.0 million in 2013 and 2012, respectively.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Legacy's revenues from the sale of oil were $286.3 million and $264.5 million for the years ended December 31, 2012 and 2011, respectively. Legacy's revenues from the sale of NGLs were $14.6 million and $18.9 million for the years ended December 31, 2012 and 2011, respectively. Legacy's revenues from the sale of natural gas were $45.6 million and $53.5 million for the years ended December 31, 2012 and 2011, respectively. The $21.8 million increase in oil revenue reflects an increase in oil production of 386 MBbls (13%) due primarily to acquisitions of producing properties during 2012, including twelve days of production from the COG 2012 Acquisition, and, to a lesser extent, our development activities that were primarily focused on oil-weighted projects in the Permian Basin. These production increases were partially offset by a $3.84 per Bbl (4%) decrease in realized oil sales price from $89.62 for the year ended December 31, 2011, to $85.78 for the year ended December 31, 2012. This decrease in realized oil price was primarily caused by an increased average oil differential of approximately $2.75 per Bbl as well as a lower average price of WTI crude oil. The $4.3 million decrease in NGL revenues reflects a decrease in realized NGL price of $0.30 per Gal (23%) from $1.30 per Gal for the year ended December 31, 2011, to $1.00 per Gal for the year ended December 31, 2012. The $7.9 million decrease in natural gas revenues reflects a $1.67 per Mcf (28%) decrease in natural gas sales price from $6.05 per Mcf for the year ended December 31, 2011 to $4.38 per Mcf for the year ended December 31, 2012, which primarily reflects a lower weighted average NYMEX Henry Hub index natural gas prices of approximately $1.24 per MMbtu in 2012. We primarily report and account for our Permian Basin natural gas volumes inclusive of the NGL content contained within those natural


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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 substantially higher than NYMEX Henry Hub natural gas prices due to this NGL content. Along with lower weighted average NYMEX Henry Hub prices in 2012 compared to 2011, our realized natural gas prices also reflect lower positive differentials in 2012 over NYMEX Henry Hub prices, which reflects the lower average prices of the NGL content in our Permian Basin natural gas production during 2012 compared to 2011. This realized price decline was partially offset by an increase in natural gas production of approximately 1,575 MMcf (18%) due primarily to the full year impact during 2012 of our 2011 acquisitions of producing properties which were natural gas-weighted and, to a lesser extent, twelve days of production from the COG 2012 Acquisition, our other 2012 acquisitions and our development activities. The Wolfberry play, which is our primary focus of development activity in the Permian Basin, produces mostly oil but also a significant amount of NGL-rich casinghead natural gas.

For the year ended December 31, 2012, Legacy recorded $38.5 million of net gains on oil and natural gas derivatives. Commodity derivative gains and losses represent the changes in fair value of our commodity derivative contracts during the period and are primarily based on oil and natural gas futures prices. Accordingly, the net gain recognized during the year ended December 31, 2012 is primarily due to a decrease in oil futures prices and, to a lesser extent, a decrease in natural gas futures prices during the period. For the year ended December 31, 2011, Legacy recorded $6.9 million of net gains on oil and natural gas derivatives. Settlements of such contracts resulted in cash receipts of $5.9 million and $0.6 million during 2012 and 2011, respectively.

Legacy's oil and natural gas production expenses, excluding ad valorem taxes, increased to $103.4 million ($19.08 per Boe) for the year ended December 31, 2012 from $87.6 million ($18.37 per Boe) for the year ended December 31, 2011. Production expenses increased primarily because of (i) $5.1 million related to increases in workover and other one-time well failure related expenses due to both increases in number of incidents as well as average cost per job, (ii) $0.8 million of increased production expenses for the twelve days of activity related to the COG 2012 Acquisition and (iii) production expenses from other acquisitions. Legacy's ad valorem tax expense increased to $9.5 million ($1.76 per Boe) for the year ended December 31, 2012 from $9.3 million ($1.95 per Boe) for the year ended December 31, 2011 primarily due to the properties acquired during 2012.

Legacy's production and other taxes were $20.8 million and $20.3 million for the years ended December 31, 2012 and 2011, respectively. Production and other taxes increased because of higher total revenues in 2013, as production and other taxes are assessed as a percentage of revenue and that percentage remained relatively unchanged between 2012 and 2011.

Legacy's general and administrative expenses were $24.5 million and $23.1 million for the years ended December 31, 2012 and 2011, respectively. General and administrative expenses increased approximately $1.4 million between periods primarily due to $3.3 million of increased salaries due to the hiring of additional personnel commensurate with the growth of our asset base partially offset by a $1.9 million charge, recognized in the fourth quarter of 2011, related to the termination of a purchase and sale agreement and related due diligence costs, as well as lower unit-based compensation of $0.5 million during 2012 due to decreases in our unit price between December 31, 2011 and December 31, 2012.

Legacy's depletion, depreciation, amortization and accretion expense, or DD&A, was $102.1 million and $88.2 million for the years ended December 31, 2012 and 2011, respectively, reflecting primarily the increase in production and cost basis related to our recent acquisitions and development activity partially offset by increased reserves related to our development activities and acquisitions during the year ended December 31, 2012 compared to the year ended December 31, 2011. Our depletion rate per Boe for the year ended December 31, 2012 was $18.84 compared to $18.48 for the year ended December 31, 2011.

Impairment expense was $37.1 million and $24.5 million for the years ended December 31, 2012 and 2011, respectively. In 2012, Legacy recognized $22.8 million of impairment expense in 64 separate producing fields, due primarily to the decrease in commodity prices including regional oil differentials during the year ended December 31, 2012, combined with higher lifting costs, which decreased the expected future cash flows below the carrying value of the assets. In addition, Legacy recognized $6.5 million of impairment related to the reduction in the carrying value of a property in which Legacy has entered into an option agreement to sell. The third party exercised this option subsequent to year end, on January 3, 2013. The remaining $7.8 million was impairment


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of goodwill recognized on an acquisition of oil and natural gas properties during 2012 as a result of a purchase and sale agreement Legacy entered into with a third party to acquire certain oil and natural gas properties. As is customary in the industry, the purchase price of the properties was negotiated as of the date of the agreement. During the period between the agreement date and the date of closing the acquisition, oil futures prices declined significantly, thereby reducing the fair value of the properties acquired at the date of close. Since oil derivatives we entered into on the agreement date related to expected production from the acquired properties constitute separate transactions, our derivatives do not affect the associated fair value of the oil and natural gas properties acquired. Because the purchase price exceeded the fair value of the properties acquired at the time of closing in May 2012, goodwill was recognized and subsequently tested for impairment. As a result of this test, all of the goodwill associated with this acquisition was impaired. In . . .

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