updated 5/4/2011 5:16:36 PM ET 2011-05-04T21:16:36

MIDLAND, Texas, May 4, 2011 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced first quarter results for 2011. The final unaudited Quarterly Report will be released and filed on or about May 6, 2011.

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

 
  Three Months Ended
  March 31, December 31, March 31,
  2011 2010 2010
  (dollars in millions)
Production (Boe/d)  11,356  10,337  8,767
Revenue $72.8 $62.3 $49.7
Commodity derivative cash settlements $1.7 $4.8 $4.8
Expenses $54.7 $48.1 $43.8
Operating income (loss) $18.1 $14.2 $5.9
Unrealized gain (loss) on commodity derivatives ($77.1) ($36.6) $7.1
Net income (loss) ($60.4) ($18.7) $10.2
Adjusted EBITDA (*) $42.3 $39.7 $32.7
Development capital expenditures $11.9 $13.6 $5.2
Distributable Cash Flow (*) $23.6 $21.5 $22.1
* 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.

Highlights of the first quarter of 2011 compared to the fourth quarter of 2010 include the following:

  • Production increased 10% to 11,356 Boe per day in the first quarter of 2011 from 10,337 Boe per day in the fourth quarter of 2010 due to production from acquisitions, most notably our acquisition of Permian Basin assets for $100.8 million that closed on December 22, 2010, as well as increased development drilling, primarily on our operated Wolfberry locations. From the fourth quarter of 2010 to the first quarter of 2011, our oil production increased by 5%, our natural gas production increased by 14%, and our NGL production increased by 7%. These production increases were partially offset by the impact of record cold weather in the Permian Basin in February, which forced us to shut-in some Wolfberry and Southeast New Mexico wells due to freeze-offs caused by power blackouts. The power blackouts also caused significant area refinery downtime lasting a month or more, reducing demand for Permian Basin crude oil. As a consequence of this downtime and increased industry activity, the demand for oil trucking services increased and a buildup of oil inventory resulted across the Permian Basin and Texas Panhandle. As a result of these takeaway capacity issues, we experienced an oil inventory buildup in excess of 25,000 barrels in the Permian Basin. We estimate that the curtailed production and inventory buildup reduced our sales volumes by approximately 550 Boe per day during the first quarter. The refineries are back online and oil trucking services are making headway on excess inventories, which we expect to result in improved sales volumes in the second quarter.

     
  • Average realized prices, excluding commodity derivatives settlements, were $71.20 per Boe in the first quarter of 2011, up 9% from $65.53 per Boe in the fourth quarter of 2010. Average realized oil prices increased 11% to $87.67 per Bbl in the first quarter from $78.93 per Bbl in the fourth quarter, average realized natural gas prices increased 1% to $5.78 per Mcf in the first quarter from $5.71 per Mcf in the fourth quarter, and average realized NGL prices increased 12% to $1.28 per gallon in the first quarter from $1.14 per gallon in the fourth quarter. Our average realized natural gas prices are favorably impacted by the high NGL content in our Permian Basin casinghead natural gas.

     
  • Oil, NGL and natural gas sales, excluding commodity derivatives settlements, were $72.8 million in the first quarter of 2011, up 17% from $62.3 million in the fourth quarter of 2010 due to both increased production and higher realized commodity prices.

     
  • Production expenses, excluding taxes, increased 19% to $21.5 million in the first quarter of 2011 from $18.0 million in the fourth quarter of 2010. On an average unit cost per Boe, production expenses increased 11% to $21.03 per Boe in the first quarter from $18.92 per Boe in the fourth quarter. Production expenses increased during the first quarter primarily because of an industry-wide increase in cost of services and certain operating costs due to a higher level of industry activity caused by higher oil prices.  In addition to the cost increases driven by higher oil prices, we also incurred several non-recurring costs including (i) approximately $1.0 million for three remedial workover projects to restore production, and (ii) approximately $0.4 million of workover expenses to improve production on the Permian Basin properties we acquired in December 2010. 

     
  • Legacy's general and administrative expenses were $6.4 million or $6.22 per Boe during the first quarter of 2011 compared to $5.9 million or $6.23 per Boe during the fourth quarter of 2010.  General and administrative expenses increased approximately $0.5 million between periods primarily due to seasonal professional services fees related to our year-end audit, Form 10-K, proxy materials, tax preparation (including our Schedule K-1s), reserve report preparation and related legal costs. This increase was partially offset by a decrease of non-cash compensation expense to $1.9 million during the first quarter of 2011 from $2.3 million during the fourth quarter of 2010.

     
  • Cash settlements received on our commodity derivatives during the first quarter of 2011 were $1.7 million compared to $4.8 million received during the fourth quarter of 2010, with the decrease attributable to higher realized commodity prices during the first quarter. Our production was 74% hedged in the first quarter compared to 72% hedged in the fourth quarter. We reported an unrealized loss of $77.1 million on our commodity derivatives portfolio in the first quarter compared to an unrealized loss of $36.6 million in the fourth quarter. Like the unrealized loss in the fourth quarter of 2010, the unrealized loss in the first quarter of 2011 was caused by an increase in both oil and natural gas futures prices between the end of the previous quarter and the end of the current quarter. 

     
  • Adjusted EBITDA increased 6% to $42.3 million during the first quarter of 2011 from $39.7 million during the fourth quarter of 2010, as higher production volumes and higher realized commodity prices were only partially offset by lower realized commodity derivative settlements and higher expenses. (See "Non-GAAP Financial Measures" and the associated table for a discussion of management's use of Adjusted EBITDA in this release and a reconciliation of Legacy's consolidated net income to Adjusted EBITDA.)

     
  • Development capital expenditures decreased to $11.9 million in the first quarter of 2011 from $13.6 million in the fourth quarter of 2010. Our capital expenditures during the first quarter are in line with our previously announced $52 million capital expenditures budget for 2011, which reflects our one-rig operated Wolfberry drilling program as well as other operated and non-operated oil drilling projects primarily in the Permian Basin. During the fourth quarter of 2010, our $13.6 million of capital expenditures were approximately $1.9 million higher than our fourth quarter budget primarily due to investments in the drilling of non-operated oil wells. 

     
  • Distributable cash flow increased by 10% in the first quarter of 2011 to $23.6 million compared to $21.5 million in the fourth quarter of 2010, as higher Adjusted EBITDA and lower development capital expenditures were partially offset by higher cash settlements of long-term incentive plan unit awards.

     
  • Distributable cash flow per unit increased to $0.54 per unit in the first quarter of 2011 from $0.52 per unit in the fourth quarter of 2010, as increased distributable cash flow more than offset the impact of an increased average number of units during the first quarter due to a full quarter impact from our November 2010 equity offering.

     
  • We experienced a net loss of $60.4 million, or $1.39 per unit, in the first quarter of 2011, as higher production volumes and realized prices were more than offset by higher expenses, lower realized commodity derivatives settlements, $77.1 million of unrealized losses on our commodity derivatives and a $1.0 million impairment charge on our oil and natural gas properties. We experienced a net loss of $18.7 million, or $0.45 per unit, in the fourth quarter of 2010, which included $36.6 million of unrealized losses on our commodity derivatives and a $0.9 million impairment charge on our oil and natural gas properties.

Cary D. Brown, Chairman and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, commented: "Legacy persevered and produced strong results during the first quarter of 2011 despite weather-related production issues and an increasing cost environment. Compared to the fourth quarter of 2010, we grew our production by 10%, our adjusted EBITDA by 6%, and our distributable cash flow by 10% during the first quarter. In addition, we announced approximately $81 million of acquisitions, including our pending $67 million acquisition of Permian Basin properties that is scheduled to close on May 5, 2011. We also announced an increase in our 2011 development capital budget in March to $52 million, which reflects the favorable economics associated with our operated and non-operated oil drilling projects. We continue to be encouraged by the results of our development drilling, particularly those associated with our operated Wolfberry projects, which are exceeding our expectations. Based on our strong drilling results and recent acquisitions, we increased our quarterly distribution to $0.53 per unit, which will be paid on May 13, 2011. Finally, after deducting $11.9 million of development capital expenditures, we generated approximately $23.6 million or $0.54 per unit of distributable cash flow, covering our $0.53 distribution by 1.02 times." 

Steven H. Pruett, President and Chief Financial Officer, commented, "We are pleased with our first quarter results despite the challenges that we encountered. As discussed in a previous press release, we entered into an amended and restated $1 billion, five-year credit agreement with an initial borrowing base of $500 million, up from our previous borrowing base of $410 million. With the anticipated closing of our $67 million acquisition, we expect to have approximately $100 million of pro forma availability under our credit agreement. As we continue to make acquisitions, we will determine whether we need to pursue a redetermination of our borrowing base to reflect our expanded asset base. With very strong public capital markets and our expanded credit facility, we are able to finance our drilling program and potentially larger acquisitions."

Commodity Derivatives Contracts

We have entered into the following oil and natural gas derivatives contracts, including swaps, collars and three-way collars, to help mitigate the risk of changing commodity prices. As of May 4, 2011, we had entered into derivatives agreements to receive average NYMEX West Texas Intermediate oil and WAHA, ANR-Oklahoma, and CIG-Rockies natural gas prices as summarized below starting with April 2011 through December 2015:

WTI:

  Annual  Average Price
Calendar Year Volumes (Bbls) Price per Bbl Range per Bbl
April - December 2011  1,659,001 $89.09 $67.33 - $140.00
2012  1,511,121 $83.05 $67.72 - $109.20
2013  1,051,243 $84.73 $80.10 - $90.50
2014  513,514 $88.68 $87.50 - $90.50
2015  145,051 $90.50 $90.50

We have entered into multiple NYMEX West Texas Intermediate crude oil derivative three-way collar contracts. Each contract combines a long put, a short put and a short call. The use of the long put combined with the short put allows us to sell a call at a higher price thus establishing a higher ceiling and limiting our exposure to future settlement payments while also restricting our downside risk to the difference between the long put and the short put if the price of NYMEX West Texas Intermediate crude oil drops below the price of the short put. This allows us to settle for WTI market plus the spread between the short put and the long put in a case where the market price has fallen below the short put fixed price. In regards to our three-way collar contracts, if the market price has fallen below the short put fixed price, we would receive the market price plus either $25 or $30 per barrel, depending on the contract. The following table summarizes the three-way oil collar contracts currently in place as of May 4, 2011:

         
  Annual Average Short Average Long Average Short
Calendar Year Volumes (Bbls) Put Price Put Price Call Price
2012  329,400 $67.50 $93.33 $112.65
2013  452,870 $63.02 $88.63 $110.19
2014  536,880 $62.55 $88.06 $115.55
2015  514,050 $63.20 $88.20 $119.18

Additionally, we have entered into a costless collar for NYMEX WTI crude oil with the following attributes:

  Annual  Floor Ceiling
Calendar Year Volumes (Bbl) Price Price
April - December 2011  51,400  $ 120.00  $ 156.30
2012  65,100  $ 120.00  $ 156.30

Natural Gas:

    Average Price
Calendar Year Volumes (MMBtu) Price per MMBtu Range per MMBtu
April - December 2011  4,972,462 $5.77 $4.15 - $8.70
2012  4,406,990 $6.21 $4.72 - $8.70
2013  3,270,254 $5.72 $5.00 - $6.89
2014  1,749,104 $5.76 $5.40 - $6.47
2015  1,020,000 $5.80 $5.79 - $5.82

Additionally, we have entered into a costless collar for WAHA natural gas with the following attributes:

    Floor Ceiling
Calendar Year Volumes (MMBtu) Price Price
2012  360,000  $ 4.00  $ 5.45

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 and natural gas index prices.

Quarterly Report on Form 10-Q

The consolidated financial statements and related footnotes will be available in our March 31, 2011 Form 10-Q, which will be filed on or about May 6, 2011.

Conference Call

As announced on April 27, 2011, Legacy will host an investor conference call to discuss Legacy's results on Thursday, May 5, 2011 at 9:00 a.m. (Central Time). Investors may access the conference call by dialing 877-266-0479. A replay of the call will be available through Monday, May 9, 2011, by dialing 706-645-9291 or 800-642-1687 and entering replay code 63833426, or by going to the Investor Relations tab of Legacy's website ( www.LegacyLP.com ). The prepared portion of the call is open to all interested parties on a listen-only basis. Following our prepared remarks, we will be pleased to answer questions from our listeners and investors.  

About Legacy Reserves LP

Legacy Reserves LP is an independent oil and natural gas 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 .

The Legacy Reserves logo is available at http://www.globenewswire.com/newsroom/prs/?pkgid=3201

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,  Dec. 31, March 31,
  2011 2010 2010
  (In thousands, except per unit data)
Revenues:      
Oil sales  $ 59,265  $ 50,755  $ 37,748
Natural gas liquids (NGL) sales  4,250  3,532  3,750
Natural gas sales  9,253  8,029  8,169
Total revenues  72,768  62,316  49,667
       
Expenses:      
Oil and natural gas production  23,757  19,781  15,070
Production and other taxes  4,357  3,714  2,919
General and administrative  6,358  5,921  4,761
Depletion, depreciation, amortization and accretion  19,560  17,537  13,115
Impairment of long-lived assets  1,047  852  7,916
(Gain) loss on disposal of assets  (409)  280  14
       
Total expenses  54,670  48,085  43,795
       
Operating income  18,098  14,231  5,872
       
Other income (expense):      
Interest income  2  1  3
Interest expense  (3,377)  (1,214)  (7,333)
Equity in income of partnership  29  27  23
Realized and unrealized net gains (losses) on  (75,456)  (31,740)  11,861
commodity derivatives      
Other  4  17  (33)
       
Income (loss) before income taxes  (60,700)  (18,678)  10,393
       
Income tax (expense) benefit  330  6  (173)
       
Net income (loss)  $ (60,370)  $ (18,672)  $ 10,220
       
Income (loss) per unit --      
basic and diluted  $ (1.39)  $ (0.45)  $ 0.26
       
Weighted average number of units used in       
computing net income (loss) per unit       
Basic  43,529  41,541  39,216
       
Diluted  43,529  41,541  39,219
       
LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEET (UNAUDITED)
(dollars in thousands)
   
  March 31,
  2011
ASSETS
Current assets:  
Cash and cash equivalents  $ 1,765
Accounts receivable, net:  
Oil and natural gas  35,259
Joint interest owners  13,351
Other  317
Fair value of derivatives  4,861
Prepaid expenses and other current assets  2,386
   
Total current assets  57,939
   
Oil and natural gas properties, at cost:  
Proved oil and natural gas properties, at cost, using the  
successful efforts method of accounting  1,199,115
Unproved properties  12,543
Accumulated depletion, depreciation and amortization  (362,341)
   849,317
Other property and equipment, net of accumulated depreciation and  
amortization of $2,723  2,933
Operating rights, net of amortization of $2,655  4,362
Other assets, net of amortization of $5,277  7,949
Investment in equity method investee  173
   
Total assets  $ 922,673
   
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:  
Accounts payable  $ 4,746
Accrued oil and natural gas liabilities  40,409
Fair value of derivatives  42,780
Asset retirement obligation  18,246
Other  7,541
   
Total current liabilities  113,722
   
Long-term debt  339,000
Asset retirement obligation  93,858
Fair value of derivatives  66,185
Other long-term liabilities  1,276
   
Total liabilities  614,041
Commitments and contingencies  
Unitholders' equity:  
Limited partners' equity - 43,531,276 units issued and  
outstanding at March 31, 2011  308,571
General partner's equity (approximately 0.05%)  61
Total unitholders' equity  308,632
   
Total liabilities and unitholders' equity  $ 922,673
   
LEGACY RESERVES LP
SELECTED FINANCIAL AND OPERATING DATA
  Three Months Ended
  March 31,  Dec. 31,  March 31,
  2011 2010 2010
  (In thousands, except per unit data)
Revenues:      
Oil sales  $ 59,265  $ 50,755  $ 37,748
Natural gas liquid sales  4,250  3,532  3,750
Natural gas sales  9,253  8,029  8,169
       
Total revenue  $ 72,768  $ 62,316  $ 49,667
       
Expenses:      
Oil and natural gas production  $ 21,497  $ 17,992  $ 14,156
Ad valorem taxes  $ 2,260  $ 1,789  $ 914
       
Total oil and natural gas production including ad valorem taxes  $ 23,757  $ 19,781  $ 15,070
Production and other taxes  $ 4,357  $ 3,714  $ 2,919
General and administrative  $ 6,358  $ 5,921  $ 4,761
Depletion, depreciation, amortization and accretion  $ 19,560  $ 17,537  $ 13,115
       
Realized commodity derivative settlements:      
Realized gain (loss) on oil derivatives  $ (1,140)  $ 1,491  $ 2,907
Realized loss on natural gas liquid derivatives  $ --   $ --   $ (39)
Realized gain on natural gas derivatives  $ 2,816  $ 3,331  $ 1,921
       
Production:      
Oil (MBbls)  676  643  504
Natural gas liquids (Mgals)  3,317  3,110  3,457
Natural gas (MMcf)  1,601  1,407  1,216
Total (MBoe)  1,022  951  789
Average daily production (Boe/d)  11,356  10,337  8,767
       
Average sales price per unit (excluding commodity derivatives):    
Oil price per barrel  $ 87.67  $ 78.93  $ 74.90
Natural gas liquid price per gallon  $ 1.28  $ 1.14  $ 1.08
Natural gas price per Mcf  $ 5.78  $ 5.71  $ 6.72
Combined (per Boe)  $ 71.20  $ 65.53  $ 62.95
       
Average sales price per unit (including realized commodity derivative settlements):  
Oil price per barrel  $ 85.98  $ 81.25  $ 80.66
Natural gas liquid price per gallon  $ 1.28  $ 1.14  $ 1.07
Natural gas price per Mcf  $ 7.54  $ 8.07  $ 8.30
Combined (per Boe)  $ 72.84  $ 70.60  $ 69.02
       
NYMEX oil index prices per barrel:      
Beginning of Period  $ 91.38  $ 79.97  $ 79.36
End of Period  $ 106.72  $ 91.38  $ 83.76
       
NYMEX gas index prices per Mcf:      
Beginning of Period  $ 4.41  $ 3.87  $ 5.57
End of Period  $ 4.39  $ 4.41  $ 3.87
       
Average unit costs per Boe:      
Oil and natural gas production  $ 21.03  $ 18.92  $ 17.94
Ad valorem taxes  $ 2.21  $ 1.88  $ 1.16
Production and other taxes  $ 4.26  $ 3.91  $ 3.70
General and administrative  $ 6.22  $ 6.23  $ 6.03
Depletion, depreciation, amortization and accretion  $ 19.14  $ 18.44  $ 16.62
       

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.  All such information is also available on our website under the Investor Relations link.

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, as well as our ability to meet our debt covenant compliance tests. Management believes that these financial measures indicate to investors whether or not cash flow is being generated at a level that can sustain or support an increase in our quarterly distribution rates. 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 or any other GAAP measure of liquidity or 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;
     
  • Unit-based compensation expense related to LTIP unit awards accounted for under the equity or liability methods;   
     
  • Unrealized (gain) loss on oil and natural gas derivatives; and
     
  • Equity in (income) loss of partnership.

Distributable Cash Flow is defined as Adjusted EBITDA less:

  • Cash interest expense;
     
  • Cash income taxes;
     
  • Cash settlements of LTIP unit awards; and
     
  • Development 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,  Dec. 31,  March 31,
  2011 2010 2010
  (dollars in thousands)
Net income (loss)  $ (60,370)  $ (18,672)  $ 10,220
Plus:      
Interest expense   3,377  1,214  7,333
Income tax expense (benefit)  (330)  (6)  173
Depletion, depreciation, amortization and accretion  19,560  17,537  13,115
Impairment of long-lived assets  1,047  852  7,916
Equity in income of partnership  (29)  (27)  (23)
Unit-based compensation expense  1,910  2,261  1,022
Unrealized loss (gain) on oil and natural gas derivatives  77,132  36,561  (7,072)
Adjusted EBITDA  $ 42,297  $ 39,720  $ 32,684
       
Less:      
Cash interest expense  4,545  4,275  3,703
Cash settlements of LTIP unit awards  2,285  358  1,702
Development capital expenditures  11,909  13,629  5,202
Distributable Cash Flow  $ 23,558  $ 21,458  $ 22,077
       
CONTACT: Legacy Reserves LP
         Steven H. Pruett, 432-689-5200
         President and Chief Financial Officer

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