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Press release from GlobeNewswire (a Nasdaq OMX company)

Legacy Reserves LP Announces First Quarter 2013 Results

Monday, May 06, 2013

Legacy Reserves LP Announces First Quarter 2013 Results

13:27 EDT Monday, May 06, 2013

MIDLAND, Texas, May 6, 2013 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq: LGCY) today announced first quarter results for 2013. Financial results contained herein are preliminary and subject to the final, unaudited financial statements included in Legacy's Form 10-Q to be filed on or about May 8, 2013.

A summary of selected financial information follows. For consolidated financial statements, please see accompanying tables.

 
  Three Months Ended
  March 31, December 31, March 31,
  2013 2012 2012
  (dollars in millions)
Production (Boe/d)  19,711  15,729  14,440
Revenue $108.9 $90.5 $92.6
Adjusted EBITDA (*) $64.4 $51.6 $55.6
Distributable Cash Flow (*) $34.9 $24.7 $36.9
* Non-GAAP financial measure. Please see Adjusted EBITDA and Distributable Cash Flow table at the end of this press release for a reconciliation of these measures to their nearest comparable GAAP measure.

Q1 2013 highlights include:

  • Our production increased 25% to a record 19,711 Boe/d primarily due to a full quarter of production from our $502.6 million Permian Basin acquisition from Concho Resources Inc. ("2012 COG Acquisition") that closed on December 20, 2012. This increased production was partially offset by lower than expected natural gas and NGL production due to continuing third-party gathering system and processing plant issues that impacted our Permian Basin and Texas Panhandle production.
     
  • We generated $108.9 million of revenue and a record $64.4 million of EBITDA, representing 20% and 25% respective increases over results in the prior quarter.
     
  • After deducting $17.0 million of maintenance capital expenditures, we generated $34.9 million of Distributable Cash Flow or $0.61 per unit, covering our first quarter distribution by 1.06 times.
     
  • We announced our tenth consecutive increase in our quarterly distribution, starting the year at $0.575 per unit which represents 3.6% year-over-year growth.

Cary D. Brown, Chairman, President and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, commented: "Legacy started 2013 with some of the best quarterly results in our history despite record crude oil differentials and natural gas infrastructure issues.  Our integration of the Concho assets is going very smoothly, as first quarter acquired production of approximately 5,250 Boe/d met our initial Q1 production estimate of 5,238 Boe/d despite unforeseen infrastructure issues that curtailed some of our production. These outstanding initial results are the product of a lot of hard work from our employees.    

"Company-wide, we generated record quarterly production of over 19,700 Boe/d and Adjusted EBITDA of $64.4 million, which were both up 25% compared to our fourth quarter 2012 results. We achieved these results despite third-party gathering system and processing plant issues that impacted our production in both the Permian Basin and Texas Panhandle, along with record crude oil differentials in the Permian Basin and high differentials in the Rockies. Due to several refineries returning to production as well as additional takeaway capacity coming online, the Midland-to-Cushing differential has fallen significantly over the past several weeks. We expect the Midland-to-Cushing differential to be at reasonable levels for most of the remainder of 2013, and we expect our Rockies differentials to moderate as well.          

"While our primary focus during the first quarter was on the integration of the largest acquisition in our history, we continued to make several small bolt-on acquisitions and evaluated a broad variety of larger opportunities. We are pleased with our current pipeline of potential acquisitions in all of our core areas. Based on our strong operation of existing wells and new capital work, we generated $34.9 million of Distributable Cash Flow or $0.61 per unit and increased our distribution for the tenth consecutive quarter to $0.575 per unit, resulting in 1.06 times coverage."

Dan Westcott, Executive Vice President and Chief Financial Officer, commented, "We are very pleased with our integration efforts of the Concho assets and our strong financial and operational results during the first quarter. On March 26, our 20-member bank group reaffirmed our borrowing base at $800 million. As of May 6, we had $475 million of debt outstanding under our revolving credit facility, giving us approximately $325 million of current availability. With plenty of availability under our credit facility and favorable capital markets conditions, we are confident in our ability to finance our 2013 growth initiatives."

Financial and Operating Results – First Quarter 2013 Compared to Fourth Quarter 2012

  • Production increased by 25% to a record 19,711 Boe/d from 15,729 Boe/d in the fourth quarter of 2012 primarily due to a full quarter of production from the 2012 COG Acquisition. In the first quarter, we generated approximately 5,250 Boe/d of production from the 2012 COG Acquisition compared to approximately 640 Boe/d in the fourth quarter, in which we only realized twelve days of production. This increased production was partially offset by lower than expected natural gas and NGL production due to continuing third-party gathering system and processing plant issues that impacted our Permian Basin and Texas Panhandle production.
     
  • Average realized prices, excluding commodity derivatives settlements, were $61.37 per Boe in the first quarter, down 2% from $62.51 per Boe in the fourth quarter. Average realized oil prices increased 1% to $81.11 per Bbl in the first quarter from $80.69 per Bbl in the fourth quarter. This increase was attributable to an estimated 7% increase in average West Texas Intermediate ("WTI") crude oil prices that was almost entirely offset by a significant increase (approximately $5.90 per barrel) in our company-wide oil differential, as our Permian Basin differentials reached record levels and our Rockies differentials increased significantly. Most notably, the Midland-to-Cushing/WTI differential increased to approximately $7.70 per barrel in the first quarter from $3.71 per barrel in the fourth quarter. Over the past several weeks, the Midland-to-Cushing differential has fallen significantly, as several refineries have returned to production and additional takeaway capacity has come online. Average realized natural gas prices decreased 9% to $4.28 per Mcf in the first quarter from $4.71 per Mcf in the fourth quarter primarily due to a smaller, positive differential to Henry Hub prices in the first quarter that primarily reflects the curtailment of a portion of our NGL-rich natural gas production in the Permian Basin. Since NGLs are embedded in the value of our Permian Basin natural gas, the inclusion of a lower amount of such NGLs had a negative effect on our average realized natural gas price. Average realized prices on our separately reported NGLs increased 10% to $1.16 per gallon in the first quarter from $1.05 per gallon in the fourth quarter. These NGL volumes, almost all of which are from our Mid-Continent assets, are heavier on average than NGLs in our Permian Basin natural gas and have benefitted from the much more favorable pricing associated with heavier NGLs.
     
  • Production expenses, excluding taxes, per Boe decreased 7% to $18.26 per Boe in the first quarter from $19.59 per Boe in the fourth quarter primarily attributable to the lower cost per Boe properties added in the 2012 COG Acquisition and lower workover and various other expenses. Production expenses, excluding taxes, increased to $32.4 million in the first quarter from $28.3 million in the fourth quarter.
     
  • Legacy's general and administrative expenses excluding unit-based/LTIP compensation expense totaled $5.3 million during the first quarter compared to $6.0 million in the fourth quarter.  This decrease was mostly attributable to acquisition-related expenses in the fourth quarter that were not incurred in the first quarter. Furthermore, while we have hired all of the necessary field personnel to manage the 2012 COG assets, we are still in the process of hiring additional personnel to help us more efficiently manage our larger asset base.  Legacy's total general and administrative expenses were $6.3 million during the first quarter compared to $5.9 million during the fourth quarter. LTIP expense increased to a $1.0 million expense in the first quarter compared to a $0.1 million benefit in the fourth quarter primarily due to fluctuations in our unit price.
     
  • Cash settlements received on our commodity derivatives during the first quarter were $2.6 million compared to $3.9 million received during the fourth quarter. The increase in WTI crude oil prices between December and March resulted in a positive one-month lag effect on our crude oil hedges, with our cash settlements received being approximately $1.1 million higher during the first quarter. In contrast, this lag effect caused our cash settlements received on our oil hedges to be approximately $1.4 million lower during the fourth quarter due to falling oil prices during that period.
     
  • Total development capital expenditures were flat at $19.7 million in the first quarter compared to $19.7 million in the fourth quarter. Our development capital expenditures in the first quarter were primarily focused on our Wolfberry drilling program, where we continue to see positive results. Other activity included attractive non-operated drilling projects in the Permian Basin (approximately 29% of total development capital expenditures for the quarter) and various other development projects mostly in the Permian Basin but in our other core areas as well.

Commodity Derivatives Contracts

We have entered into the following oil and natural gas derivatives contracts, including swaps and three-way collars, to help mitigate the risk of changing commodity prices. As of May 6, 2013, we had entered into derivatives agreements to receive average NYMEX WTI crude oil and Waha, ANR-Oklahoma, and CIG-Rockies natural gas prices as summarized below starting with April 2013 through December 2017:

Crude Oil (WTI):

    Average Price
Calendar Year Volumes (Bbls) Price per Bbl Range per Bbl
April-December 2013  1,610,855 $91.00 $80.10 - $106.23
2014  1,520,764 $91.54 $87.50 - $103.75
2015  545,351 $91.98 $88.50 - $100.20
2016  228,600 $87.94 $86.30 - $99.85
2017  182,500 $84.75 $84.75

We have also entered into multiple NYMEX WTI crude oil derivative three-way collar contracts as follows:

    Average Short Average Long Average Short
Calendar Year Volumes (Bbls) Put Price Put Price Call Price
April-December 2013  908,670 $66.13 $91.51 $107.36
2014  1,453,880 $65.54 $90.73 $110.65
2015  1,308,500 $64.67 $89.67 $112.21
2016  621,300 $63.37 $88.37 $106.40
2017  72,400 $60.00 $85.00 $104.20

Additionally, we have entered into swaps for the Midland-to-Cushing/WTI crude oil differential with the following attributes:

    Average Price
Time Period Volumes (Bbls) Price per Bbl Range per Bbl
April-December 2013  2,200,000 ($1.47) $(1.25) - $(1.75)

Natural Gas (WAHA, ANR-Oklahoma and CIG-Rockies hubs):

    Average Price
Calendar Year Volumes (MMBtu) Price per MMBtu Range per MMBtu
April-December 2013  7,657,903 $4.28 $3.23 - $6.89
2014  8,271,254 $4.32 $3.61 - $6.47
2015  1,339,300 $5.65 $5.14 - $5.82
2016  219,200 $5.30 $5.30

Location and quality differentials attributable to our properties are not reflected in the above prices. The agreements provide for monthly settlement based on the difference between the agreement fixed price and the actual reference oil or natural gas index price.

Quarterly Report on Form 10-Q

Our consolidated financial statements and related footnotes will be available in our Form 10-Q for the quarter ended March 31, 2013, which will be filed on or about May 8, 2013.

Conference Call

As announced on April 22, 2013, Legacy will host an investor conference call to discuss Legacy's results on Tuesday, May 7, 2013, at 9:00 a.m. (Central Time). Those wishing to participate in the conference call should dial 877-266-0479. A replay of the call will be available through Tuesday, May 14, 2013, by dialing 855-859-2056 or 404-537-3406 and entering replay code 43840115. Those wishing to listen to the live or archived web cast via the Internet should go to the Investor Relations tab of our website at www.legacylp.com. Following our prepared remarks, we will be pleased to answer questions from securities analysts and institutional portfolio managers and analysts; the complete call is open to all other interested parties on a listen-only basis.

About Legacy Reserves LP

Legacy Reserves LP is a master limited partnership headquartered in Midland, Texas, focused on the acquisition and development of oil and natural gas properties primarily located in the Permian Basin, Mid-Continent and Rocky Mountain regions of the United States. Additional information is available at www.legacylp.com.

Cautionary Statement Relevant to Forward-Looking Information

This press release contains forward-looking statements relating to our operations that are based on management's current expectations, estimates and projections about its operations. Words such as "anticipates," "expects," "intends," "plans," "targets," "projects," "believes," "seeks," "schedules," "estimated," and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: realized oil and natural gas prices; production volumes, lease operating expenses, general and administrative costs and finding and development costs; future operating results and the factors set forth under the heading "Risk Factors" in our annual and quarterly reports filed with the SEC. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this press release. Unless legally required, Legacy undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

LEGACY RESERVES LP
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
       
  Three Months Ended
  March 31, December 31, March 31,
  2013 2012 2012
  (In thousands, except per unit data)
Revenues:      
Oil sales  $ 90,357  $ 74,157  $ 76,137
Natural gas liquids (NGL) sales  3,342  3,850  3,726
Natural gas sales  15,180  12,448  12,784
       
Total revenues  108,879  90,455  92,647
       
Expenses:      
Oil and natural gas production  35,351  30,929  24,888
Production and other taxes  6,927  5,737  5,217
General and administrative  6,281  5,922  6,450
Depletion, depreciation, amortization and accretion  41,652  29,102  22,839
Impairment of long-lived assets  1,743  14,510  1,301
(Gain) loss on disposal of assets  (219)  568  (3,011)
       
Total expenses  91,735  86,768  57,684
       
Operating income  17,144  3,687  34,963
       
Other income (expense):      
Interest income  8  5  4
Interest expense  (10,692)  (6,003)  (4,336)
Equity in income of equity method investees  44  23  26
Realized and unrealized net gains (losses) on      
commodity derivatives  (13,005)  4,409  (23,089)
Other  7  (31)  32
Income (loss) before income taxes  (6,494)  2,090  7,600
       
Income tax expense  (211)  (218)  (211)
       
Net income (loss)  $ (6,705)  $ 1,872  $ 7,389
       
Income (loss) per unit -      
basic and diluted  $ (0.12)  $ 0.04  $ 0.15
       
Weighted average number of units used in       
computing net income (loss) per unit -      
Basic  57,077  52,416  47,802
       
Diluted  57,077  52,454  47,848
 
LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(dollars in thousands)
     
  March 31, December 31,
  2013 2012
ASSETS  
Current assets:    
Cash and cash equivalents  $ 2,341  $ 3,509
Accounts receivable, net:    
Oil and natural gas  47,611  37,547
Joint interest owners  32,197  27,851
Other  411  551
Fair value of derivatives  4,030  15,158
Prepaid expenses and other current assets  3,158  3,294
     
Total current assets  89,748  87,910
     
Oil and natural gas properties, at cost:    
Proved oil and natural gas properties using the successful efforts    
method of accounting  2,079,971  2,078,961
Unproved properties  69,624  65,968
Accumulated depletion, depreciation, amortization and impairment  (601,957)  (573,003)
     
   1,547,638  1,571,926
Other property and equipment, net of accumulated depreciation and    
amortization of $4,944 and $4,618, respectively  2,607  2,646
Operating rights, net of amortization of $3,654 and $3,531, respectively  3,362  3,486
Fair value of derivatives  18,036  15,834
Other assets, net of amortization of $8,426 and $7,909, respectively  19,189  7,804
Investments in equity method investees  4,334  393
     
Total assets  $ 1,684,914  $ 1,689,999
     
LIABILITIES AND UNITHOLDERS' EQUITY  
Current liabilities:    
Accounts payable  $ 10,446  $ 1,822
Accrued oil and natural gas liabilities  60,523  50,162
Fair value of derivatives  17,410  10,801
Asset retirement obligation  29,646  29,501
Other  14,513  11,437
     
Total current liabilities  132,538  103,723
Long-term debt  778,087  775,838
Asset retirement obligation  132,574  132,682
Fair value of derivatives  4,249  5,590
Other long-term liabilities  1,833  1,886
     
Total liabilities  1,049,281  1,019,719
Commitments and contingencies    
Unitholders' equity:    
Limited partners' equity - 57,193,842 and 57,038,942 units issued and     
outstanding at March 31, 2013 and December 31, 2012, respectively  635,549  670,183
General partner's equity (approximately 0.03%)  84  97
     
Total unitholders' equity  635,633  670,280
     
Total liabilities and unitholders' equity  $ 1,684,914  $ 1,689,999
 
LEGACY RESERVES LP
SELECTED FINANCIAL AND OPERATING DATA
       
  Three Months Ended
  March 31, December 31, March 31,
  2013 2012 2012
  (In thousands, except per unit data)
Revenues:      
Oil sales  $ 90,357  $ 74,157  $ 76,137
Natural gas liquids (NGL) sales  3,342  3,850  3,726
Natural gas sales  15,180  12,448  12,784
       
Total revenues  $ 108,879  $ 90,455  $ 92,647
       
Expenses:      
Oil and natural gas production  $ 32,385  $ 28,343  $ 22,983
Ad valorem taxes  2,966  2,586  1,905
       
Total oil and natural gas production including ad valorem taxes  $ 35,351  $ 30,929  $ 24,888
       
Production and other taxes  $ 6,927  $ 5,737  $ 5,217
       
General and administrative excluding LTIP  $ 5,295  $ 6,046  $ 4,893
LTIP expense (benefit)  986  (124)  1,557
       
Total general and administrative  $ 6,281  $ 5,922  $ 6,450
       
Depletion, depreciation, amortization and accretion  $ 41,652  $ 29,102  $ 22,839
       
Realized commodity derivative settlements:      
Realized gains (losses) on oil derivatives  $ 229  $ 738  $ (6,203)
Realized gains on natural gas derivatives  $ 2,406  $ 3,146  $ 4,150
       
Production:      
Oil (MBbls)  1,114  919  788
Natural gas liquids (MGal)  2,893  3,670  3,490
Natural gas (MMcf)  3,546  2,643  2,658
Total (MBoe)  1,774  1,447  1,314
Average daily production (Boe/d)  19,711  15,729  14,440
       
Average sales price per unit (excluding commodity derivatives):      
Oil price (per Bbl)  $ 81.11  $ 80.69  $ 96.62
Natural gas liquids price (per Gal)  $ 1.16  $ 1.05  $ 1.07
Natural gas price (per Mcf)  $ 4.28  $ 4.71  $ 4.81
Combined (per Boe)  $ 61.37  $ 62.51  $ 70.51
       
Average sales price per unit (including realized commodity derivative gains/losses):      
Oil price (per Bbl)  $ 81.32  $ 81.50  $ 88.75
Natural gas liquids price (per Gal)  $ 1.16  $ 1.05  $ 1.07
Natural gas price (per Mcf)  $ 4.96  $ 5.90  $ 6.37
Combined (per Boe)  $ 62.86  $ 65.20  $ 68.95
       
NYMEX oil index prices per Bbl:      
Beginning of Period  $ 91.82  $ 92.19  $ 98.83
End of Period  $ 97.23  $ 91.82  $ 103.02
       
NYMEX gas index prices per Mcf:      
Beginning of Period  $ 3.35  $ 3.32  $ 2.99
End of Period  $ 4.02  $ 3.35  $ 2.13
       
Average unit costs per Boe:      
Oil and natural gas production  $ 18.26  $ 19.59  $ 17.49
Ad valorem taxes  $ 1.67  $ 1.79  $ 1.45
Production and other taxes  $ 3.90  $ 3.96  $ 3.97
General and administrative excluding LTIP  $ 2.98  $ 4.18  $ 3.72
Total general and administrative  $ 3.54  $ 4.09  $ 4.91
Depletion, depreciation, amortization and accretion  $ 23.48  $ 20.11  $ 17.38

Non-GAAP Financial Measures

This press release, the financial tables and other supplemental information include "Adjusted EBITDA" and "Distributable Cash Flow", both of which are non-generally accepted accounting principles ("non-GAAP") measures which may be used periodically by management when discussing our financial results with investors and analysts. The following presents a reconciliation of each of these non-GAAP financial measures to their nearest comparable generally accepted accounting principles ("GAAP") measure. 

Adjusted EBITDA and Distributable Cash Flow are presented as management believes they provide additional information and metrics relative to the performance of our business, such as the cash distributions we expect to pay to our unitholders. Management believes that both Adjusted EBITDA and Distributable Cash Flow are useful to investors because these measures are used by many companies 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 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. 

"Adjusted EBITDA" and "Distributable Cash Flow" should not be considered as alternatives 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;
  • (Gain) loss on disposal of assets;
  • Equity in (income) loss of equity method investees;
  • Unit-based compensation expense (benefit) related to LTIP unit awards accounted for under the equity or liability methods;
  • Minimum payments earned in excess of overriding royalty interest; and
  • Unrealized (gains) losses on oil and natural gas derivatives.

Distributable Cash Flow is defined as Adjusted EBITDA less:

  • Cash interest expense including the accrual of interest expense related to our senior notes which is paid on a semi-annual basis;
  • Cash income taxes;
  • Cash settlements of LTIP unit awards; and
  • Maintenance capital expenditures.

The following table presents a reconciliation of our consolidated net income (loss) to Adjusted EBITDA and Distributable Cash Flow:

 
  Three Months Ended 
  March 31, December 31, March 31,
  2013 2012 2012
  (dollars in thousands)
Net income (loss)  $ (6,705)  $ 1,872  $ 7,389
Plus:      
Interest expense   10,692  6,003  4,336
Income tax expense  211  218  211
Depletion, depreciation, amortization and accretion  41,652  29,102  22,839
Impairment of long-lived assets  1,743  14,510  1,301
(Gain) loss on sale of assets  (219)  568  (3,011)
Equity in income of equity method investees  (44)  (23)  (26)
Unit-based compensation expense (benefit)  986  (124)  1,557
Minimum payments earned in excess of overriding royalty interest (1)  400  --   -- 
Unrealized (gains) losses on oil and natural gas derivatives  15,640  (525)  21,036
Adjusted EBITDA  $ 64,356  $ 51,601  $ 55,632
       
Less:      
Cash interest expense  11,578  6,991  4,254
Cash settlements of LTIP unit awards  858  184  2,268
Maintenance capital expenditures (2)  17,000    
Total development capital expenditures    19,693  12,200
Distributable Cash Flow  $ 34,920  $ 24,733  $ 36,910
(1) Minimum payments earned in excess of overriding royalties earned under a contractual agreement expiring December 31, 2019.
(2) Beginning in the first quarter of 2013, Legacy began deducting only maintenance capital expenditures instead of
total development capital expenditures in the computation and presentation of Distributable Cash Flow, which results
in the measure of Distributable Cash Flow not being comparable to those during any prior periods.
CONTACT: Legacy Reserves LP
Dan Westcott
Executive Vice President and Chief Financial Officer
(432) 689-5200

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