updated 3/2/2011 7:47:02 PM ET 2011-03-03T00:47:02

MIDLAND, Texas, March 2, 2011 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced annual and fourth quarter results for 2010. This unaudited financial information is preliminary and is subject to adjustments to our final audited financial statements to be released on or about March 4, 2011 in conjunction with the filing of Legacy's Form 10-K for the year-ended December 31, 2010.

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

  Three Months Ended Twelve Months Ended
  December 31, September 30, December 31,
  2010 2010 2010 2009
  (dollars in millions)
Production (Boe/d)  10,337  9,804  9,611  8,225
Revenue $62.3 $52.8 $216.4 $137.3
Commodity Derivative Cash Settlements $4.8 $6.3 $20.1 $52.5
Expenses $48.1 $45.0 $178.1 $140.8
Operating income (loss) $14.2 $7.8 $38.3 ($3.5)
Unrealized loss on commodity derivatives ($36.6) ($26.2) ($21.5) ($128.0)
Net income (loss) ($18.7) ($20.2) $10.8 ($92.8)
Adjusted EBITDA (*) $39.7 $35.7 $140.4 $120.0
Development Capital $13.6 $9.0 $32.9 $13.7
Distributable Cash Flow (*) $21.5 $22.2 $89.0 $88.0
         
* 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 full year 2010 include the following:

  • Production increased 17% to 9,611 Boe per day in 2010 from 8,225 Boe per day in 2009 due primarily to our approximately $280 million of acquisitions and approximately $33 million of development capital expenditures.
     
  • Proved reserves as of December 31, 2010 increased by 42% to 52.8 MMBoe (86% PDP, 74% liquids) compared to 37.1 MMBoe (84% PDP, 72% liquids) as of December 31, 2009 due primarily to our acquisitions and drilling activity as well as commodity price increases.
     
  • Adjusted EBITDA increased 17% to $140.4 million in 2010 from $120.0 million in 2009.
     
  • Our total unitholder return during 2010 was approximately 56.6%, including distributions.
     
  • To partially fund our acquisitions, we completed two equity offerings during 2010 in which we issued approximately 8.3 million units and raised net proceeds of approximately $179 million.

Highlights of the fourth quarter of 2010 include the following:

  • Production increased 5% to 10,337 Boe per day in the fourth quarter from 9,804 Boe per day in the third quarter due to production from recent acquisitions, workovers and increased development drilling, primarily on our operated Wolfberry locations.
     
  • Adjusted EBITDA increased 11% to $39.7 million during the fourth quarter from $35.7 million during the third quarter.
     
  • We closed our acquisition of Permian Basin properties from Concho Resources on December 22, 2010, for $100.8 million (including estimated post-closing adjustments). This acquisition was the second-largest in our history after our acquisition of Wyoming properties from SM Energy in February 2010 for approximately $125.5 million.
     
  • In anticipation of the closing of our Permian Basin acquisition, we closed a 3.45 million unit offering on November 23, 2010 that raised net proceeds of approximately $83.6 million.

Cary D. Brown, Chairman and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, commented: "After the challenges of 2009, Legacy experienced its most productive year to date in 2010. We grew our annual production and adjusted EBITDA by 17% and our proved reserves by 42%. In addition, we closed approximately $280 million of acquisitions, including our two largest acquisitions in which we established a new core area in the Rockies and significantly expanded our Permian Basin asset base. We ended 2010 on a high note, as we grew our production by 5% and our EBITDA by 11% compared to the third quarter due to our acquisitions and development activities. We continue to be encouraged by the results of our development drilling and workover projects, which are meeting or exceeding our expectations. In addition, we closed our Permian Basin acquisition from Concho during the fourth quarter, which contributed only 10 days of production and cash flow to our results. Due to our growth in 2010 as well as our positive outlook for 2011, we increased our quarterly distribution to $0.525 per unit, which was paid on February 14, 2011. We are pleased to report that during the fourth quarter, even after we deducted $13.6 million of development capital expenditures and pre-funded our Permian Basin acquisition with the issuance of additional units in November, we still generated approximately $21.5 million or $0.52 per unit of distributable cash flow with coverage of 0.99 times our $0.525 distribution. For the year, after deducting $32.9 million of development capital expenditures, we generated approximately $89.0 million or $2.21 per unit of distributable cash flow, covering our $2.085 distribution by 1.06 times. 

"We face new challenges in 2011 due to the robust oil price environment. With the recent increases in oil prices, we are witnessing an increased level of competition for oil-weighted acquisitions in the Permian Basin as well as a rising cost environment. Despite these challenges, we believe that we will continue to grow through accretive acquisitions in all of our core areas. With these acquisitions and a $45 million capital expenditures budget to develop a portion of our multi-year drilling inventory, we look forward to another highly productive year in 2011." 

Steven H. Pruett, President and Chief Financial Officer, commented, "We are very pleased with our fourth quarter and annual results from 2010. Our active acquisition program during 2010 was fully supported by our bank group as well as our unitholders and equity underwriters through two successful follow-on offerings. As of December 31, 2010 we had approximately $85 million of borrowing capacity under our credit facility and current $410 million borrowing base. After our recent meeting with our bank group, we anticipate an increase to our borrowing base due to our newly acquired Permian Basin assets from Concho, our additional commodity hedges and other smaller acquisitions. We expect to announce this borrowing base increase along with an extension of the term of our credit facility in late March of this year. With strong public capital markets and an expanded credit facility, we are confident in our ability to fund our growth initiatives in 2011. With a full year contribution from our Permian Basin acquisition and with the impact of our drilling program, management of Legacy expects to be able to recommend further distribution increases to the Board of Directors of our general partner in 2011."

Financial and Operating Results – Annual 2010 Results Compared to Annual 2009 Results

  • Production increased 17% to 9,611 Boe per day in 2010 from 8,225 Boe per day in 2009 due to production from acquisitions, including our $125.5 million acquisition of Wyoming assets that closed on February 17, 2010, as well as our major workover projects and development drilling. Our oil production increased by 30% from 2009 to 2010 due to production from our oil assets in Wyoming and oil focused drilling in the Permian Basin. Despite our acquisitions and drilling efforts, our increase in natural gas production was limited to 3% while our natural gas liquids ("NGL") production decreased by 15%, as these volumes were significantly impacted by gathering system and processing plant downtime from one of our natural gas purchasers in the Texas Panhandle. Our year-end Permian Basin acquisition contributed only ten days to 2010 results, and will impact the full year of 2011.
     
  • Oil, NGL and natural gas sales, excluding commodity derivatives settlements, were $216.4 million in 2010, up 58% from $137.3 million in 2009, as a result of increased production and significantly increased commodity prices.
     
  • Average realized prices, excluding commodity derivatives settlements, were $61.68 per Boe in 2010, up 35% from $45.73 per Boe in 2009. Average realized oil prices increased 29% to $74.02 per Bbl in 2010 from $57.40 per Bbl in 2009, average realized natural gas prices increased 30% to $5.76 per Mcf in 2010 from $4.43 per Mcf in 2009, and average realized NGL prices increased 39% to $1.06 per gallon in 2010 from $0.76 per gallon in 2009. Our average realized natural gas prices are significantly impacted by the high NGL content in our Permian Basin casinghead natural gas.
         
  • Production expenses, excluding taxes, increased 42% to $63.0 million in 2010 from $44.3 million in 2009. On an average unit cost per Boe, production expenses increased 22% to $17.97 per Boe in 2010 from $14.76 per Boe in 2009.  Production expenses increased primarily because of (i) $8.8 million of production expenses related to the Wyoming and Permian acquisitions previously mentioned, (ii) $1.1 million related to increases in workover activity, (iii) $0.9 million in one-time expenses related to regulatory compliance and casualty losses, (iv) production expenses from other acquisitions and (v) an industry-wide increase in cost of services and certain operating costs that are directly related to the higher commodity prices experienced during 2010, including the cost of electricity, which powers artificial lift equipment and pumps involved in the production of oil, and the higher level of industry activity resulting from higher oil prices. Legacy's ad valorem tax expense increased to $6.2 million ($1.77 per Boe) in 2010 from $4.5 million ($1.50 per Boe) in 2009 primarily due to the properties acquired in the Wyoming acquisition that closed in February 2010.
     
  • Legacy's general and administrative expenses were $19.3 million or $5.49 per Boe and $15.5 million or $5.16 per Boe for the years ended December 31, 2010 and 2009, respectively. General and administrative expenses increased approximately $3.8 million between these time periods primarily due to (i) a $2.4 million increase in non-cash compensation expense related to the long-term incentive plan ("LTIP") in 2010 due to increases in Legacy's unit price, (ii) $0.7 million of acquisition costs and (iii) $0.3 million of one-time expenses related to Legacy's accounting system conversion, the ultimate implementation of which occurred in January 2011.
     
  • Cash settlements received on our commodity derivatives during 2010 were $20.1 million compared to $52.5 million received during 2009, with the decrease primarily attributable to higher realized commodity prices during 2010. Our production was 75% hedged in 2010 compared to 71% hedged in 2009. We reported an unrealized loss of $21.5 million on our commodity derivatives portfolio in 2010 compared to an unrealized loss of $128.0 million in 2009. The unrealized loss in 2010 was caused by an increase in NYMEX oil futures prices between year-end 2009 and year-end 2010 that was partially offset by a decrease in NYMEX natural gas futures prices during the same time frame. As a result of this increase in oil prices and unrealized loss of $21.5 million, our commodity derivatives net asset of approximately $6.9 million as of December 31, 2009 became a $14.7 million commodity derivatives net liability as of December 31, 2010. In addition, our large unrealized commodity derivatives loss in 2009 was caused by a sharp increase in NYMEX oil futures prices between year-end 2008 and year-end 2009.
     
  • Adjusted EBITDA increased 17% to $140.4 million during 2010 from $120.0 million in 2009, as higher production volumes and higher realized commodity prices were only partially offset by lower realized commodity derivative settlements, higher production expenses, higher ad valorem and production taxes, and higher general and administrative 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 increased to $32.9 million in 2010 from $13.7 million in 2009. Legacy resumed active development drilling during 2010, particularly during the second half of 2010 during which 69% of our 2010 expenditures were incurred due to oilfield service delays involving both drilling rigs and fracture stimulation services during the first half of 2010. Due to the financial crisis and much lower commodity prices, Legacy greatly reduced its capital budget in 2009, as most of our $13.7 million in capital expenditures were spent on workovers and recompletions as well as non-operated drilling projects.
     
  • Distributable cash flow remained relatively flat in 2010 at $89.0 million compared to $88.0 million in 2009, as higher Adjusted EBITDA and slightly lower cash interest expense was mostly offset by higher development capital expenditures.
     
  • Distributable cash flow per unit decreased to $2.21 per unit in 2010 from $2.74 per unit in 2009 due to much higher development capital expenditures in 2010 and an increased average number of units in 2010 from equity offerings in September 2009, January 2010 and November 2010.
     
  • We generated net income of $10.8 million, or $0.27 per unit, in 2010, as higher production volumes and realized prices were partially offset by higher expenses, lower realized commodity derivatives settlements, $21.5 million of unrealized losses on our commodity derivatives and $13.4 million in impairment charges on our oil and natural gas properties.  We generated a net loss of $92.8 million, or $2.89 per unit, in 2009, which included $128.0 million of unrealized losses on our commodity derivatives and $9.2 million in impairment charges on our oil and natural gas properties.

Financial and Operating Results – Fourth Quarter 2010 Results Compared to Third Quarter 2010 Results

  • Production increased 5% to 10,337 Boe per day in the fourth quarter of 2010 from 9,804 Boe per day in the third quarter of 2010 due to production from recent acquisitions, workovers and increased development drilling, primarily on our operated Wolfberry locations.  From the third quarter to the fourth quarter, our oil and natural gas production both increased by 6%, while our NGL production increased by 1%. Our fourth quarter volumes were less impacted by gathering system and processing plant downtime from one of our natural gas purchasers in the Texas Panhandle compared to our third quarter volumes. In addition, our recent Permian Basin acquisition only contributed 10 days of production in the fourth quarter, as it was closed on December 22.
     
  • Oil, NGL and natural gas sales, excluding commodity derivatives settlements, were $62.3 million in the fourth quarter of 2010, up 18% from $52.8 million in the third quarter of 2010 due to both increased production and realized commodity prices.
     
  • Average realized prices, excluding commodity derivatives settlements, were $65.53 per Boe in the fourth quarter of 2010, up 12% from $58.51 per Boe in the third quarter of 2010. Average realized oil prices increased 12% to $78.93 per Bbl in the fourth quarter from $70.21 per Bbl in the third quarter, average realized natural gas prices increased 6% to $5.71 per Mcf in the fourth quarter from $5.40 per Mcf in the third quarter, and average realized NGL prices increased 19% to $1.14 per gallon in the fourth quarter from $0.96 per gallon in the third quarter. Our average realized natural gas prices are significantly impacted by the high NGL content in our Permian Basin casinghead natural gas.
     
  • Production expenses, excluding taxes, increased 21% to $18.0 million in the fourth quarter of 2010 from $14.9 million in the third quarter of 2010. On an average unit cost per Boe, production expenses increased 14% to $18.92 per Boe in the fourth quarter from $16.53 per Boe in the third quarter. Production expenses increased primarily because of (i) $1.0 million related to increases in workover activity, (ii) $0.6 million in one-time expenses related to regulatory compliance and integration costs related to a recent bolt-on acquisition, (iii) production expenses from other acquisitions and (iv) an industry-wide increase in cost of services and certain operating costs that are directly related to the higher commodity prices experienced during the fourth quarter, including the cost of electricity, which powers artificial lift equipment and pumps involved in the production of oil, and the higher level of industry activity resulting from higher oil prices.
     
  • Legacy's general and administrative expenses were $5.9 million or $6.23 per Boe and $4.5 million or $5.03 per Boe for the fourth and third quarters of 2010, respectively. General and administrative expenses increased approximately $1.4 million between periods primarily due to an approximate $1.0 million increase in non-cash unit compensation expense in the fourth quarter.
     
  • Cash settlements received on our commodity derivatives during the fourth quarter of 2010 were $4.8 million compared to $6.3 million received during the third quarter of 2010, with the decrease primarily attributable to higher realized commodity prices during the fourth quarter. Our production was 72% hedged in the fourth quarter compared to 76% hedged in the third quarter. We reported an unrealized loss of $36.6 million on our commodity derivatives portfolio in the fourth quarter compared to an unrealized loss of $26.2 million in the third quarter. The unrealized loss in the fourth quarter was caused by an increase in NYMEX oil and natural gas futures prices between the end of the third quarter and the end of the fourth quarter. In contrast, the unrealized loss in the third quarter was caused by an increase in NYMEX oil futures prices between the end of the second quarter and the end of the third quarter. This loss was partially offset by an unrealized gain related to the decrease in NYMEX natural gas futures prices over the same time frame.
     
  • Adjusted EBITDA increased 11% to $39.7 million during the fourth quarter of 2010 from $35.7 million during the third quarter of 2010, as higher production volumes and higher realized commodity prices were only partially offset by lower realized commodity derivative settlements, higher production expenses, higher ad valorem and production taxes, and higher general and administrative 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 increased to $13.6 million in the fourth quarter of 2010 from $9.0 million in the third quarter of 2010. With our $31 million budget for development capital expenditures during 2010, we previously estimated $11.7 million of capital expenditures during the fourth quarter. Our actual expenditures were approximately $1.9 million higher than our budget primarily due to investments in the drilling of non-operated wells during the fourth quarter.
     
  • Distributable cash flow decreased slightly in the fourth quarter of 2010 to $21.5 million compared to $22.2 million in the third quarter of 2010, as higher Adjusted EBITDA was more than offset by higher development capital expenditures.
     
  • Distributable cash flow per unit decreased to $0.52 per unit in the fourth quarter of 2010 from $0.55 per unit in the third quarter of 2010 due to higher development capital expenditures in the fourth quarter and an increased average number of units in the fourth quarter due to the November 2010 equity offering that partially pre-funded our acquisition of Permian Basin assets from Concho.
     
  • We generated a net loss of $18.7 million, or $0.45 per unit, in the fourth quarter of 2010, as higher production volumes and realized prices were more offset by higher expenses, lower realized commodity derivatives settlements, $36.6 million of unrealized losses on our commodity derivatives and a $0.9 million impairment charge on our oil and natural gas properties. We generated a net loss of $20.2 million, or $0.50 per unit, in the third quarter of 2010, which included $26.2 million of unrealized losses on our commodity derivatives and a $4.2 million impairment charge on our oil and natural gas properties.

New Commodity Derivatives Contracts

From December 2010 through February 2011, Legacy entered into crude oil and natural gas derivatives contracts with five counterparties, all of which are lenders to Legacy under its credit agreement. These contracts are summarized as follows:

Oil Swap (WTI)    
  Annual   
Calendar Year Volumes (Bbls) Price per Bbl
2011  50,100  $ 95.52
       
Oil 3-Way Collars (WTI)      
  Annual Average Short Average Long Average Short
Calendar Year Volumes (Bbls) Put Price Put Price Call Price
2012  109,800  $ 62.50  $ 90.00  $ 108.18
2013  109,500  $ 62.50  $ 90.00  $ 110.30
2014  109,500  $ 62.50  $ 90.00  $ 112.48
2015  109,500  $ 65.00  $ 90.00  $ 117.88
     
Natural Gas Swaps (WAHA)    
    Average Price
Calendar Year Volumes (MMBtu) Price per MMBtu Range per MMBtu
2011  1,867,500  $ 4.30 $4.15 -- $4.36
2012  549,000  $ 4.72 $4.72
2013  547,500  $ 5.00 $5.00
       
Natural Gas Collar (WAHA)    
    Floor Ceiling
Calendar Year Volumes (MMBtu) Price Price
2012  360,000  $ 4.00  $ 5.45

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 March 2, 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 January 2011 through December 2015:

WTI:

  Annual  Average Price
Calendar Year Volumes (Bbls) Price per Bbl Range per Bbl
2011  2,148,410  $ 88.33 $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

On May 3, 2010, October 6, 2010, January 12, 2011 and February 4, 2011, we entered into 18 separate 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 March 2, 2011:

  Annual Average Short Average Long Average Short
Calendar Year Volumes (Bbls) Put Price Put Price Call Price
2012  183,000  $ 61.50  $ 88.00  $ 104.83
2013  379,870  $ 60.72  $ 86.44  $ 107.97
2014  463,880  $ 60.59  $ 86.18  $ 114.70
2015  441,050  $ 61.24  $ 86.24  $ 118.65

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
2011  68,300  $ 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
2011  4,905,816  $ 6.27 $4.15 -- $8.70
2012  2,906,990  $ 6.97 $4.72 -- $8.70
2013  1,950,254  $ 6.13 $5.00 -- $6.89
2014  609,104  $ 6.36 $5.95 -- $6.47

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.

Annual Report on Form 10-K

Our consolidated, audited financial statements and related footnotes will be available in our annual 2010 Form 10-K, which will be filed on or about March 4, 2011.

Conference Call

As announced on February 23, 2011, Legacy will host an investor conference call to discuss Legacy's results on Thursday, March 3, 2011 at 8:30 a.m. (Central Time). Investors may access the conference call by dialing 877-266-0479.  For those who cannot listen to the live broadcast, a replay of the call will be available through Monday, March 7, 2011, by dialing 706-645-9291 or 800-642-1687 and entering replay code 45542838, or by going to the Investor Relations tab of Legacy's website ( www.LegacyLP.com ). We will take live 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 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 Twelve Months Ended
  December 31, September 30, December 31,
  2010 2010 2010 2009
  (In thousands, except per unit data)
Revenues:        
Oil sales  $ 50,755  $ 42,620  $ 172,754  $ 103,319
Natural gas liquids (NGL) sales  3,532  2,956  13,670  11,565
Natural gas sales  8,029  7,198  29,965  22,395
Total revenues  62,316  52,774  216,389  137,279
         
Expenses:        
Oil and natural gas production  19,781  16,585  69,228  48,814
Production and other taxes  3,714  3,096  12,683  8,145
General and administrative  5,921  4,536  19,265  15,502
Depletion, depreciation, amortization and accretion  17,537  16,175  62,894  58,763
Impairment of long-lived assets  852  4,173  13,412  9,207
Loss on disposal of assets  280  453  592  378
         
Total expenses  48,085  45,018  178,074  140,809
         
Operating income (loss)  14,231  7,756  38,315  (3,530)
         
Other income (expense):        
Interest income  1  3  10  9
Interest expense  (1,214)  (8,215)  (25,766)  (13,222)
Equity in income of partnership  27  22  97  31
Realized and unrealized net losses on        
commodity derivatives  (31,740)  (19,819)  (1,400)  (75,554)
Other  17  (15)  90  (11)
         
Income (loss) before income taxes  (18,678)  (20,268)  11,346  (92,277)
         
Income tax (expense) benefit  6  83  (537)  (554)
         
Net income (loss)  $ (18,672)  $ (20,185)  $ 10,809  $ (92,831)
         
Income (loss) per unit --        
basic and diluted  $ (0.45)  $ (0.50)  $ 0.27  $ (2.89)
         
Weighted average number of units used in         
computing net income (loss) per unit         
Basic  41,541  40,079  40,233  32,163
         
Diluted  41,541  40,079  40,237  32,163
         
LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEET (UNAUDITED)
(dollars in thousands)
  December 31,
  2010
ASSETS
Current assets:  
Cash and cash equivalents  $ 3,478
Accounts receivable, net:  
Oil and natural gas  27,050
Joint interest owners  10,378
Other  91
Fair value of derivatives  7,763
Prepaid expenses and other current assets  1,838
Total current assets  50,598
   
Oil and natural gas properties, at cost:  
Proved oil and natural gas properties, at cost, using the  
successful efforts method of accounting  1,174,498
Unproved properties  12,543
Accumulated depletion, depreciation and amortization  (343,205)
   843,836
Other property and equipment, net of accumulated depreciation and  
amortization of $2,437  2,917
Deposit on pending acquisition  112
Operating rights, net of amortization of $2,529  4,488
Fair value of derivatives  4,000
Other assets, net of amortization of $4,809  3,331
Investment in equity method investee  144
Total assets  $ 909,426
   
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:  
Accounts payable  $ 631
Accrued oil and natural gas liabilities  29,654
Fair value of derivatives  14,882
Asset retirement obligation  18,333
Other  9,455
Total current liabilities  72,955
   
Long-term debt  325,000
Asset retirement obligation  92,929
Fair value of derivatives  25,540
Other long-term liabilities  1,263
Total liabilities  517,687
Commitments and contingencies  
Unitholders' equity:  
Limited partners' equity - 43,528,776 units issued and  
outstanding at December 31, 2010  391,662
General partner's equity (approximately 0.1%)  77
Total unitholders' equity  391,739
   
Total liabilities and unitholders' equity  $ 909,426
         
LEGACY RESERVES LP
SELECTED FINANCIAL AND OPERATING DATA
 
  Three Months Ended Twelve Months Ended
  December 31, September 30, December 31,
  2010 2010 2010 2009
  (In thousands, except per unit data)
Revenues:        
Oil sales  $ 50,755  $ 42,620  $ 172,754  $ 103,319
Natural gas liquid sales  3,532  2,956  13,670  11,565
Natural gas sales  8,029  7,198  29,965  22,395
Total revenue  $ 62,316  $ 52,774  $ 216,389  $ 137,279
         
Expenses:        
Oil and natural gas production  $ 17,992  $ 14,908  $ 63,024  $ 44,308
Ad valorem taxes  $ 1,789  $ 1,677  $ 6,204  $ 4,506
         
Total oil and natural gas production including ad valorem taxes  $ 19,781  $ 16,585  $ 69,228  $ 48,814
Production and other taxes  $ 3,714  $ 3,096  $ 12,683  $ 8,145
General and administrative  $ 5,921  $ 4,536  $ 19,265  $ 15,502
Depletion, depreciation, amortization and accretion  $ 17,537  $ 16,175  $ 62,894  $ 58,763
         
Realized commodity derivative settlements:        
Realized gain on oil derivatives  $ 1,491  $ 3,581  $ 9,263  $ 37,919
Realized gain (loss) on natural gas liquid derivatives  $ --   $ --   $ (39)  $ 733
Realized gain on natural gas derivatives  $ 3,331  $ 2,763  $ 10,913  $ 13,825
         
Production:        
Oil (MBbls)  643  607  2,334  1,800
Natural gas liquids (Mgals)  3,110  3,070  12,890  15,118
Natural gas (MMcf)  1,407  1,332  5,204  5,055
Total (MBoe)  951  902  3,508  3,002
Average daily production (Boe/d)  10,337  9,804  9,611  8,225
         
Average sales price per unit (excluding commodity derivatives):        
Oil price per barrel  $ 78.93  $ 70.21  $ 74.02  $ 57.40
Natural gas liquid price per gallon  $ 1.14  $ 0.96  $ 1.06  $ 0.76
Natural gas price per Mcf  $ 5.71  $ 5.40  $ 5.76  $ 4.43
Combined (per Boe)  $ 65.53  $ 58.51  $ 61.68  $ 45.73
         
Average sales price per unit (including realized commodity derivative settlements):    
Oil price per barrel  $ 81.25  $ 76.11  $ 77.99  $ 78.47
Natural gas liquid price per gallon  $ 1.14  $ 0.96  $ 1.06  $ 0.81
Natural gas price per Mcf  $ 8.07  $ 7.48  $ 7.86  $ 7.17
Combined (per Boe)  $ 70.60  $ 65.54  $ 67.42  $ 63.21
         
NYMEX oil index prices per barrel:        
Beginning of Period  $ 79.97  $ 75.63  $ 79.36  $ 44.60
End of Period  $ 91.38  $ 79.97  $ 91.38  $ 79.36
         
NYMEX gas index prices per Mcf:        
Beginning of Period  $ 3.87  $ 4.62  $ 5.57  $ 5.62
End of Period  $ 4.41  $ 3.87  $ 4.41  $ 5.57
         
Average unit costs per Boe:        
Oil and natural gas production  $ 18.92  $ 16.53  $ 17.97  $ 14.76
Ad valorem taxes  $ 1.88  $ 1.86  $ 1.77  $ 1.50
Production and other taxes  $ 3.91  $ 3.43  $ 3.62  $ 2.71
General and administrative  $ 6.23  $ 5.03  $ 5.49  $ 5.16
Depletion, depreciation, amortization and accretion  $ 18.44  $ 17.93  $ 17.93  $ 19.57

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 in our revolving credit facility 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  Twelve Months Ended 
  December 31, September 30, December 31,
  2010 2010 2010 2009
  (dollars in thousands)
Net income (loss)  $ (18,672)  $ (20,185)  $ 10,809  $ (92,831)
Plus:        
Interest expense   1,214  8,215  25,766  13,222
Income tax expense (benefit)  (6)  (83)  537  554
Depletion, depreciation, amortization and accretion  17,537  16,175  62,894  58,763
Impairment of long-lived assets  852  4,173  13,412  9,207
Gain on disposal of assets  --   --   --   (54)
Equity in income of partnership  (27)  (22)  (97)  (31)
Unit-based compensation expense  2,261  1,310  5,549  3,130
Unrealized loss on oil and natural gas derivatives  36,561  26,163  21,537  128,031
Adjusted EBITDA  $ 39,720  $ 35,746  $ 140,407  $ 119,991
         
Less:        
Cash interest expense  4,275  4,378  16,094  17,809
Cash settlements of LTIP unit awards  358  134  2,402  415
Development capital expenditures  13,629  9,026  32,917  13,727
Distributable Cash Flow  $ 21,458  $ 22,208  $ 88,994  $ 88,040
CONTACT: Legacy Reserves LP
         Steven H. Pruett, 432-689-5200
         President and Chief Financial Officer

© Copyright 2012, GlobeNewswire, Inc. All Rights Reserved

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