EXHIBIT 99.1

Legacy Reserves LP Announces Fourth Quarter and Annual 2011 Results

MIDLAND, Texas, Feb. 21, 2012 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced annual and fourth quarter results for 2011. This unaudited financial information is preliminary and is subject to adjustments to our final audited financial statements to be released on or about February 23, 2012 in conjunction with the filing of Legacy's Form 10-K for the year ended December 31, 2011.

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

Highlights of 2011 include the following:

• Production increased 36% to 13,071 Boe per day in 2011 from 9,611 Boe per day in 2010 primarily due to our $136.7 million of acquisitions of producing properties during 2011, a full-year impact of our $100.8 million Permian Basin acquisition that closed on December 22, 2010, and a record $71.6 million of development capital expenditures during 2011. 
   
• Proved reserves as of December 31, 2011 increased by 20% to 63.4 MMBoe (85% PDP, 68% liquids) compared to 52.8 MMBoe (86% PDP, 74% liquids) as of December 31, 2010 due primarily to our acquisitions and drilling activity as well as commodity price increases.
   
• Adjusted EBITDA increased 44% to $202.0 million in 2011 from $140.4 million in 2010.
   
• We increased our quarterly distributions by 4.8% to $0.55 per unit attributable to the fourth quarter of 2011 from $0.525 per unit attributable to the fourth quarter of 2010, while still maintaining distribution coverage of 1.14 times during 2011.
   
• To finance our current and future acquisition efforts, we (i) completed a 3.86 million unit equity offering in November, and (ii) amended and extended our credit agreement to a $1 billion facility with a current borrowing base of $550 million that expires in March 2016.

Highlights of the fourth quarter of 2011 include the following:

• Production remained flat at 13,750 Boe per day in the fourth quarter compared to 13,793 Boe per day in the third quarter, as production increases from recent acquisitions were offset by third party plant downtime issues that impacted a portion of our New Mexico natural gas production and weather-related oil trucking delays in the Permian Basin. 
   
• Adjusted EBITDA increased 3% to $53.8 million during the fourth quarter from $52.1 million during the third quarter.
   
• We closed $42 million of acquisitions of producing properties during the fourth quarter, all of which were in the Permian Basin.    
   
• We closed a 3.86 million unit equity offering in November that raised net proceeds of $106.7 million.

Cary D. Brown, Chairman and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, commented: "After an outstanding 2010, Legacy continued its strong growth in 2011, as we set new records for production, Adjusted EBITDA and proved reserves. We increased our annual production by 36% to an average of over 13,000 Boe per day, we increased our Adjusted EBITDA by 44% to over $200 million, and we grew our proved reserves by 20% to 63.4 MMBoe through our robust acquisition program and record $71.6 million of development capital expenditures. After closing our $100.8 million Permian Basin acquisition at the end of 2010, we closed 28 acquisitions during 2011, including $136.7 million of producing properties and another $5.5 million of undeveloped prospective acreage in the Permian Basin. While approximately 96% of our 2011 acquisitions were in the Permian Basin, we will continue to evaluate and expect to close accretive acquisitions in all of our core areas. Due to our strong results, we increased our distribution every quarter during 2011, resulting in distribution growth of 4.8% since the fourth quarter of 2010. We are pleased to report that during the fourth quarter, even after we deducted $19.5 million of development capital expenditures and an additional $1.9 million of general and administrative expenses related to our termination of a potential acquisition in Wyoming, we still generated approximately $29.4 million or $0.64 per unit of distributable cash flow with coverage of 1.16 times our $0.55 distribution. For the year, after deducting all of our $71.6 million of development capital expenditures, we generated approximately $108.5 million or $2.46 per unit of distributable cash flow, covering our $2.165 distribution by 1.14 times." 

"We continue to be encouraged by the results of our Wolfberry drilling program, which are meeting or exceeding our expectations. While our Wolfberry program will remain the focus of our operated drilling activity in 2012, our $62 million development capital budget also includes two operated horizontal 3^rd Bone Spring wells and two operated Yeso wells. With our multi-year, oil-weighted drilling inventory that is largely within the Permian Basin and our strong acquisition efforts, we believe that we are well positioned for the future and look forward to another highly productive year in 2012." 

Steven H. Pruett, President and Chief Financial Officer, commented, "We are very pleased with our fourth quarter and record annual results from 2011. Our successful November 2011 equity offering combined with our amended $1 billion credit facility positions us to execute our acquisition and development plans. As of February 21, 2012, we had approximately $200 million of borrowing capacity under our credit facility, which has a current $550 million borrowing base. With favorable conditions in the public capital markets and ample availability under our credit facility, we look forward to another year of strong financial and operational growth. We thank our employees for another solid performance and our investors and banks for supporting our growth."

Financial and Operating Results – Annual 2011 Results Compared to Annual 2010 Results

• Production increased 36% to 13,071 Boe per day in 2011 from 9,611 Boe per day in 2010 due primarily to (i) our $136.7 million of acquisitions of producing properties during 2011, (ii) a full-year impact of our $100.8 million Permian Basin acquisition that closed on December 22, 2010, as well as a full-year impact of our $125.5 million Wyoming acquisition that closed on February 17, 2010, and (iii) a record $71.6 million of development capital expenditures during 2011, which was primarily focused on our operated and non-operated Wolfberry locations but also included other oil-weighted development drilling and major workovers. Our oil production increased by 26% from 2010 to 2011 due to acquisitions and oil-focused drilling in the Permian Basin. Our natural gas production increased by 70% from 2010 to 2011 due to acquisitions, which were more natural gas-weighted in 2011, along with our development drilling, as the Wolfberry play primarily produces oil but also a significant amount of NGL-rich casinghead natural gas. Natural gas liquids ("NGL") production increased by 13% primarily due to significantly lower plant and gathering system downtime during 2011 from one of our natural gas and NGL purchasers in the Texas Panhandle compared to the downtime experienced in 2010.    
   
• Average realized prices, excluding commodity derivatives settlements, were $70.61 per Boe in 2011, up 14% from $61.68 per Boe in 2010. Average realized oil prices increased 21% to $89.62 per Bbl in 2011 from $74.02 per Bbl in 2010, average realized natural gas prices increased 5% to $6.05 per Mcf in 2011 from $5.76 per Mcf in 2010, and average realized NGL prices increased 23% to $1.30 per gallon in 2011 from $1.06 per gallon in 2010. Our average realized natural gas prices are favorably impacted by the NGL content in our Permian Basin casinghead natural gas.
   
• Oil, NGL and natural gas sales, excluding commodity derivatives settlements, were $336.9 million in 2011, up 56% from $216.4 million in 2010, as a result of significantly increased production and increased commodity prices.       
   
• Production expenses, excluding ad valorem taxes, increased 39% to $87.6 million in 2011 from $63.0 million in 2010. On an average cost per Boe basis, production expenses increased only 2% to $18.37 per Boe in 2011 from $17.97 per Boe in 2010. Production expenses increased primarily because of (i) $8.2 million of increased production expenses related to our $100.8 million Permian Basin acquisition, as this acquisition was closed on December 22, 2010 and thus only had 8 days of expense in 2010, (ii) $2.7 million related to increases in workover activity, (iii) production expenses from other acquisitions, and (iv) an industry-wide increase in cost of services and certain operating costs that are related to the higher oil prices and increased industry activity during 2011. On a per Boe basis, these increases in production expenses were partially offset by the acquisition of lower cost natural gas production during 2011, in particular our May 2011 Permian Basin acquisition that has production expenses that currently average less than $5.00 per Boe. 
   
• Legacy's general and administrative expenses were $23.1 million or $4.84 per Boe and $19.3 million or $5.49 per Boe for the years ended December 31, 2011 and 2010, respectively. General and administrative expenses increased approximately $3.8 million between periods primarily due to (i) increased salaries and benefits due to the hiring of additional personnel commensurate with the growth of our asset base, (ii) $1.9 million in additional expenses, including a $1.7 million charge and approximately $0.2 million of due diligence expenses, related to the termination of a potential acquisition in Wyoming during the fourth quarter of 2011, and (iii) a $0.8 million increase in insurance expenses encompassing corporate, director and officer and employee insurance plans. These increases were partially offset by lower unit-based compensation expense of $1.5 million, as increases in Legacy's unit price resulted in higher LTIP expense during 2010. 
   
• Cash settlements received on our commodity derivatives during 2011 were $0.6 million compared to $20.1 million received during 2010, with the decrease primarily attributable to higher realized commodity prices during 2011. Our production was 71% hedged in 2011 compared to 75% hedged in 2010. We reported unrealized gains of $6.2 million on our commodity derivatives portfolio in 2011 compared to unrealized losses of $21.5 million in 2010. We had unrealized net losses of $0.7 million from our oil derivatives during 2011 as an increase in NYMEX oil futures prices from December 31, 2010 to December 31, 2011 more than offset the increase in the average fixed price of Legacy's oil derivatives contracts, resulting in a larger net oil derivative liability.  We also had unrealized net gains of $6.9 million from our natural gas derivatives as a decrease in NYMEX natural gas futures prices from December 31, 2010 to December 31, 2011 was only partially offset by a decrease in the average fixed price of Legacy's natural gas derivative contracts, resulting in a larger net natural gas derivative asset. As a result of these unrealized gains of $6.2 million, our commodity derivatives net liability was reduced from approximately $14.7 million as of December 31, 2010 to $8.4 million as of December 31, 2011. In addition, we incurred large unrealized commodity derivatives losses of $21.5 million in 2010, as the significant increase in NYMEX oil futures prices between year-end 2009 and year-end 2010 was only partially offset by a decrease in NYMEX natural gas futures prices over the same time frame.
   
• Adjusted EBITDA increased 44% to $202.0 million during 2011 from $140.4 million in 2010, as significantly 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 $71.6 million in 2011 from $32.9 million in 2010. Our increased capital expenditures in 2011 compared to 2010 reflect (i) our continuous, one-rig Wolfberry operated drilling program in 2011, which did not start until the second half of 2010 due to a lack of availability of  drilling rigs and fracture stimulation services during the first half of 2010, (ii) improved efficiency in our drilling program during 2011, which allowed us to drill more wells, (iii) moderate increases in drilling costs, and (iv) increased non-operated development capital expenditures, which accounted for approximately 25% of our total development capital expenditures during 2011.   
   
• Distributable cash flow increased 22% to $108.5 million in 2011 from $89.0 million in 2010, as significantly higher Adjusted EBITDA was only partially offset by significantly higher development capital expenditures and higher cash interest expense that reflected higher average debt outstanding during the year.
   
• Distributable cash flow per unit increased by 11% to $2.46 per unit in 2011 from $2.21 per unit in 2010, as increased distributable cash flow was only partially offset by an increased average number of units in 2011 primarily due to equity offerings in November 2010 and November 2011. 
   
• We generated net income of $72.1 million, or $1.63 per unit, in 2011, as higher revenues and $6.2 million in unrealized gains on commodity derivatives were partially offset by higher expenses, lower realized commodity derivatives settlements, and $24.5 million in impairment charges on our oil and natural gas properties.  We generated net income of $10.8 million, or $0.27 per unit, in 2010, which included $21.5 million of unrealized losses on our commodity derivatives and $13.4 million in impairment charges on our oil and natural gas properties.

Financial and Operating Results – Fourth Quarter 2011 Results Compared to Third Quarter 2011 Results

• Production remained flat at 13,750 Boe per day in the fourth quarter compared to 13,793 Boe per day in the third quarter, as production increases primarily from recent acquisitions were offset by (i) third party plant downtime issues that impacted a portion of our New Mexico natural gas production, and (ii) oil trucking delays caused by inclement winter weather in the Permian Basin during December. The impact of these trucking delays was alleviated and our New Mexico natural gas production improved during January 2012.  
   
• Average realized prices, excluding commodity derivatives settlements, were $68.70 per Boe in the fourth quarter of 2011, up 3% from $66.49 per Boe in the third quarter of 2011. Average realized oil prices increased 7% to $89.69 per Bbl in the fourth quarter from $83.96 per Bbl in the third quarter, average realized natural gas prices decreased 11% to $5.59 per Mcf in the fourth quarter from $6.30 per Mcf in the third quarter, and average realized NGL prices decreased 7% to $1.23 per gallon in the fourth quarter from $1.32 per gallon in the third quarter. Our average realized natural gas prices are favorably impacted by the NGL content in our Permian Basin casinghead natural gas.         
    
• Oil, NGL and natural gas sales, excluding commodity derivatives settlements, were $86.9 million in the fourth quarter of 2011, up 3% from $84.4 million in the third quarter of 2011 due to higher realized oil prices.
   
• Production expenses, excluding taxes, increased 4% to $23.1 million in the fourth quarter of 2011 from $22.1 million in the third quarter of 2011. On an average unit cost per Boe, production expenses increased 5% to $18.23 per Boe in the fourth quarter from $17.41 per Boe in the third quarter. This increase reflects modest cost increases as well as increased well count and production from acquisitions and drilling. Production expenses per Boe are also impacted by expenses without associated sales volumes due to plant downtime and trucking delays mentioned previously.  
     
• Legacy's general and administrative expenses were $8.4 million or $6.68 per Boe and $3.8 million or $3.01 per Boe for the fourth and third quarters of 2011, respectively. General and administrative expenses increased approximately $4.6 million during the fourth quarter primarily due to (i) an approximate $1.6 million increase in non-cash unit compensation expense due primarily to an increase in Legacy's unit price between the end of the third quarter and the end of the fourth quarter, (ii) $1.9 million in additional expenses, including a $1.7 million charge and approximately $0.2 million of due diligence expenses, related to the termination of a potential acquisition in Wyoming, and (iii) $0.8 million for year-end professional services, due diligence expenses on closed acquisitions, and salaries and benefits for new employees.   
   
• Cash settlements received on our commodity derivatives during the fourth quarter of 2011 were $4.4 million compared to $0.8 million received during the third quarter of 2011, with the increase attributable in part to lower natural gas prices during the quarter. Unlike natural gas hedges that settle during the same month in which the corresponding volumes are hedged, crude oil hedges settle during the month after its corresponding volumes are hedged. This lag effect on crude oil hedges during a period of increasing oil prices caused our cash hedging settlements to be approximately $2.5 million higher during the fourth quarter. In contrast, this lag effect on crude oil hedges during a period of declining oil prices caused our cash hedging settlements to be approximately $2.2 million lower during the third quarter. In addition, our production was 71% hedged in the fourth quarter compared to 68% hedged in the third quarter. We also reported unrealized losses of $65.3 million on our commodity derivatives portfolio during the fourth quarter, as the impact of increasing NYMEX oil futures prices from the end of the third quarter until the end of the fourth quarter was only partially offset by a decrease in NYMEX natural gas futures prices over the same time frame. As a result of these unrealized losses, our commodity derivatives net asset of $56.9 million at September 30, 2011 was reduced to a commodity derivatives net liability of $8.4 million as of December 31, 2011. In comparison, we reported unrealized gains of $106.8 million on our commodity derivatives portfolio during the third quarter due to declining commodity prices.  
   
• Adjusted EBITDA increased 3% to $53.8 million during the fourth quarter of 2011 from $52.1 million during the third quarter of 2011, as higher realized commodity prices and higher realized commodity derivative settlements were only partially offset by 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 decreased to $19.5 million in the fourth quarter of 2011 from $22.8 million in the third quarter of 2011, as we had lower working interests on our drilling projects during the fourth quarter. 
   
• Distributable cash flow increased by 22% in the fourth quarter of 2011 to $29.4 million compared to $24.1 million in the third quarter of 2011 due to higher Adjusted EBITDA and lower development capital expenditures.
   
• Distributable cash flow per unit increased to $0.64 per unit in the fourth quarter of 2011 from $0.55 per unit in the third quarter of 2011, as higher distributable cash flow was only partially offset by an increased average number of units in the fourth quarter attributable to our November 2011 equity offering. 
   
• We reported a net loss of $58.5 million, or $1.28 per unit, in the fourth quarter of 2011, as higher realized prices and higher commodity derivatives settlements were more than offset by higher expenses, $65.3 million of unrealized losses on our commodity derivatives and $18.6 million of impairment charges on our oil and natural gas properties. We generated net income of $125.1 million, or $2.87 per unit, in the third quarter of 2011, which included $106.8 million of unrealized gains on our commodity derivatives and $4.7 million of impairment charges on our oil and natural gas properties.

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 February 21, 2012, 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 2012 through December 2016:

Oil: 

We have also 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 short put allows us to buy a put and sell a call at higher prices, thus establishing a higher ceiling and limiting our exposure to future settlement payments while also restricting our downside risk. If the market price is below the long put fixed price but above the short put fixed price, a three-way collar allows us to settle for the long put fixed price. A three-way collar also 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 February 21, 2012: 

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

Natural Gas:  

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

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 2011 Form 10-K, which will be filed on or about February 23, 2012.

Conference Call

As announced on January 20, 2012, Legacy will host an investor conference call to discuss Legacy's results on Wednesday, February 22, 2012 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 Monday, February 27, 2012, by dialing 855-859-2056 or 404-537-3406 and entering replay code 45123753. 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 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.

 

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 (excluding settlements of asset retirement obligations);
   
• Equity in (income) loss of partnership;
   
• Unit-based compensation expense related to LTIP unit awards accounted for under the equity or liability methods; and
   
• Unrealized (gains) losses on oil and natural gas derivatives.

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:

CONTACT: Legacy Reserves LP
         James R. Lawrence
         Vice President - Finance and Treasurer
         (432) 689-5200