EXHIBIT 99.1
Legacy Reserves LP Announces Second Quarter 2011 Results
MIDLAND, Texas, Aug. 3, 2011 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced its second quarter results for 2011. The final unaudited Quarterly Report will be released and filed on or about August 4, 2011.
A summary of selected financial information follows. For consolidated financial statements, please see accompanying tables.
| Three Months Ended | Six Months Ended | |||
| June 30, | March 31, | June 30, | June 30, | |
| 2011 | 2011 | 2011 | 2010 | |
| (dollars in millions) | ||||
| Production (Boe/d) | 13,363 | 11,356 | 12,365 | 9,144 |
| Revenue | $92.8 | $72.8 | $165.6 | $101.3 |
| Commodity derivative cash settlements | ($6.3) | $1.7 | ($4.6) | $9.0 |
| Expenses | $55.5 | $54.7 | $110.2 | $85.0 |
| Operating income | $37.4 | $18.1 | $55.5 | $16.3 |
| Unrealized gain (loss) on commodity derivatives | $41.9 | ($77.1) | ($35.2) | $41.2 |
| Net income (loss) | $65.9 | ($60.4) | $5.5 | $49.7 |
| Adjusted EBITDA (*) | $53.8 | $42.3 | $96.1 | $64.9 |
| Development capital expenditures | $17.4 | $11.9 | $29.3 | $10.3 |
| Distributable Cash Flow (*) | $31.4 | $23.6 | $55.0 | $45.3 |
| * 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 second quarter of 2011 compared to the first quarter of 2011 include the following:
- Production increased 18% to 13,363 Boe per day in the second quarter of 2011 from 11,356 Boe per day in the first quarter of 2011 due to production from acquisitions, most notably our acquisition of Permian Basin assets for $66 million that closed on May 5, 2011; increased development drilling, primarily on our operated Wolfberry locations; and favorable weather during the second quarter compared to the severely cold weather that significantly impacted production throughout the Permian Basin during the first quarter. From the first quarter to the second quarter, our oil production increased by 12%, our natural gas production increased by 40%, and our NGL production increased by 4%. In addition, on a year-over-year basis, our quarterly production has increased by 40%.
- Average realized prices, excluding commodity derivatives settlements, were $76.34 per Boe in the second quarter of 2011, up 7% from $71.20 per Boe in the first quarter of 2011. Average realized oil prices increased 11% to $96.93 per Bbl in the second quarter from $87.67 per Bbl in the first quarter, average realized natural gas prices increased 12% to $6.47 per Mcf in the second quarter from $5.78 per Mcf in the first quarter, and average realized NGL prices increased 7% to $1.37 per gallon in the second quarter from $1.28 per gallon in the first 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 $92.8 million in the second quarter of 2011, up 28% from $72.8 million in the first quarter of 2011 due to both increased production and higher realized commodity prices.
- Production expenses, excluding taxes, decreased 2% to $21.0 million in the second quarter of 2011 from $21.5 million in the first quarter of 2011 despite an increase in sales volume and well count. In the first quarter, we incurred approximately $1.0 million for three remedial workover projects to restore production, as well as approximately $0.4 million of workover expenses to improve production on Permian Basin properties acquired in December 2010. In addition, our latest significant Permian Basin acquisition, which closed in May 2011, contains relatively new (approximately three to seven years) natural gas wells with estimated production expenses of less than $5.00 per Boe. With a significant increase in sales volumes, lower non-recurring costs, and the addition of low cost natural gas production, production expenses per Boe decreased 18% to $17.25 per Boe in the second quarter from $21.03 per Boe in the first quarter.
- Legacy's general and administrative expenses were $4.5 million or $3.66 per Boe during the second quarter of 2011 compared to $6.4 million or $6.22 per Boe during the first quarter of 2011. This decrease was primarily due to a decrease in non-cash compensation expense to $0.5 million during the second quarter from $1.9 million during the first quarter. In addition, we incurred approximately $0.5 million of seasonal professional services fees during the first quarter that were not incurred during the second quarter.
- Cash settlements paid on our commodity derivatives during the second quarter of 2011 were $6.3 million compared to $1.7 million received during the first quarter of 2011, with the decrease attributable to higher front month prices for oil and natural gas during the second quarter. Our production was 71% hedged in the second quarter compared to 74% hedged in the first quarter. We reported an unrealized gain of $41.9 million on our commodity derivatives portfolio in the second quarter compared to an unrealized loss of $77.1 million in the first quarter. Although average realized prices were higher during the second quarter, the unrealized gain in the second quarter of 2011 was primarily caused by a decrease in oil futures prices and to a lesser degree natural gas futures prices at the end of the second quarter compared to the end of the first quarter.
- Adjusted EBITDA increased 27% to $53.8 million during the second quarter of 2011 from $42.3 million during the first quarter of 2011, as higher production volumes, higher realized commodity prices, lower production expenses and lower general and administrative expenses were only partially offset by lower realized commodity derivative settlements and higher production and ad valorem taxes. (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 $17.4 million in the second quarter of 2011 from $11.9 million in the first quarter of 2011. Our development capital expenditures include our one-rig operated Wolfberry drilling program, which is largely within budget, as well as other operated and non-operated oil drilling and recompletion projects.
- Distributable cash flow increased by 33% in the second quarter of 2011 to $31.4 million compared to $23.6 million in the first quarter of 2011, as higher Adjusted EBITDA and lower cash settlements of long-term incentive plan unit awards were partially offset by higher development capital expenditures.
- Distributable cash flow per unit increased to $0.72 per unit in the second quarter of 2011 from $0.54 per unit in the first quarter of 2011, as distributable cash flow increased during the second quarter while the average number of units stayed relatively constant between the first and second quarters.
- We generated net income of $65.9 million, or $1.51 per unit, in the second quarter of 2011, as higher revenues, lower production expenses, lower general and administrative expenses, and $41.9 million of unrealized gains on our commodity derivatives were partially offset by commodity derivative settlement payments, and higher production and ad valorem taxes. We reported a net loss of $60.4 million, or $1.39 per unit, in the first quarter of 2011, which included $77.1 million of unrealized losses on our commodity derivatives and a $1.0 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: "After a trying first quarter, Legacy produced outstanding results during the second quarter of 2011, as we significantly increased production due to our acquisitions and development activities while reducing our production expenses. During the second quarter, we increased our production by 18%, our adjusted EBITDA by 27%, and our distributable cash flow by 33% compared to the first quarter. In addition, we closed our largest acquisition of the year for $66 million in early May. Through the end of July, we have closed approximately $93 million of acquisitions during 2011 that we believe will be accretive to our distributable cash flow per unit. Our development activities also reached new heights during the second quarter, as we invested a record $17.4 million on oil and NGL-rich drilling projects that we believe will generate very favorable rates of return. The primary focus of drilling activities remains on our operated Wolfberry locations, which are performing well above our expectations. Based on our record quarter in which we generated EBITDA of $53.8 million, we increased our quarterly distribution for the third consecutive quarter to $0.54 per unit, which will be paid on August 12, 2011. Finally, we generated distributable cash flow of approximately $31.4 million, or $0.72 per unit, covering our $0.54 distribution by 1.33 times."
Steven H. Pruett, President and Chief Financial Officer, commented, "With record production and EBITDA along with strong drilling and completion results, we are excited about the outcome of our second quarter. In addition to our drilling activities, our acquisition pipeline is very strong, although we face stiff competition for oil-weighted acquisitions, especially those in the Permian Basin. At the end of July, we had a debt balance of $400 million, leaving us with approximately $100 million of availability under our credit agreement. Despite the recent lackluster performance of the broader equity market indices due to domestic and global economic uncertainties, the equity markets for MLP issuers remain strong. With our access to the public markets and our $1 billion credit facility with a current borrowing base of $500 million, we are well positioned to finance all of our growth initiatives. I want to personally thank our employees for delivering performance that has enabled us to increase our distributions by 4% and our coverage ratio by 25% over the last three quarters."
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 August 3, 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 July 2011 through June 2016:
WTI:
| Calendar Year | Annual Volumes (Bbls) | Average Price per Bbl | Price Range per Bbl |
| July - December 2011 | 1,129,684 | $89.56 | $67.33 -- $140.00 |
| 2012 | 1,602,321 | $84.05 | $67.72 -- $109.20 |
| 2013 | 1,087,743 | $85.28 | $80.10 -- $101.10 |
| 2014 | 550,014 | $89.47 | $87.50 -- $101.10 |
| 2015 | 181,551 | $92.41 | $90.50 -- $100.20 |
| 2016 | 18,200 | $99.85 | $99.85 |
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 reducing 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. With our current contracts, if the market price falls 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 in place as of August 3, 2011:
| Calendar Year | Annual Volumes (Bbls) | Average Short Put Price | Average Long Put Price | Average Short Call Price |
| 2012 | 384,600 | $67.86 | $94.29 | $113.16 |
| 2013 | 599,170 | $65.49 | $91.40 | $112.68 |
| 2014 | 719,380 | $65.71 | $91.09 | $117.67 |
| 2015 | 696,550 | $66.29 | $91.29 | $121.01 |
| 2016 | 91,000 | $75.00 | $100.00 | $127.41 |
Additionally, we have entered into a costless collar for NYMEX WTI crude oil with the following attributes:
| Calendar Year | Annual Volumes (Bbl) | Floor Price | Ceiling Price |
| July - December 2011 | 34,400 | $ 120.00 | $ 156.30 |
| 2012 | 65,100 | $ 120.00 | $ 156.30 |
Natural Gas (WAHA, ANR-Oklahoma, and CIG-Rockies hubs):
| Calendar Year | Volumes (MMBtu) | Average Price per MMBtu | Price Range per MMBtu |
| July - December 2011 | 3,416,408 | $5.73 | $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:
| Calendar Year | Volumes (MMBtu) | Floor Price | Ceiling 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 a 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 June 30, 2011 Form 10-Q, which will be filed on or about August 4, 2011.
Conference Call
As announced on July 22, 2011, Legacy will host an investor conference call to discuss Legacy's results on Thursday, August 4, 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, August 8, 2011, by dialing (855) 859-2056 or (404) 537-3406 and entering replay code 85749655. 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. 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 | Six Months Ended | |||
| June 30, | March 31, | June 30, | ||
| 2011 | 2011 | 2011 | 2010 | |
| (In thousands, except per unit data) | ||||
| Revenues: | ||||
| Oil sales | $ 73,569 | $ 59,265 | $ 132,834 | $ 79,378 |
| Natural gas liquids (NGL) sales | 4,722 | 4,250 | 8,972 | 7,182 |
| Natural gas sales | 14,544 | 9,253 | 23,797 | 14,738 |
| Total revenues | 92,835 | 72,768 | 165,603 | 101,298 |
| Expenses: | ||||
| Oil and natural gas production | 23,438 | 23,757 | 47,195 | 32,862 |
| Production and other taxes | 5,533 | 4,357 | 9,890 | 5,873 |
| General and administrative | 4,455 | 6,358 | 10,813 | 8,808 |
| Depletion, depreciation, amortization and accretion | 22,146 | 19,560 | 41,706 | 29,181 |
| Impairment of long-lived assets | 144 | 1,047 | 1,191 | 8,387 |
| Gain on disposal of assets | (235) | (409) | (645) | (142) |
| Total expenses | 55,481 | 54,670 | 110,150 | 84,969 |
| Operating income | 37,354 | 18,098 | 55,453 | 16,329 |
| Other income (expense): | ||||
| Interest income | 5 | 2 | 7 | 7 |
| Interest expense | (6,492) | (3,377) | (9,869) | (16,338) |
| Equity in income of partnership | 43 | 29 | 72 | 48 |
| Realized and unrealized net gains (losses) on commodity derivatives | 35,606 | (75,456) | (39,850) | 50,158 |
| Other | (62) | 4 | (58) | 88 |
| Income (loss) before income taxes | 66,454 | (60,700) | 5,755 | 50,292 |
| Income tax (expense) benefit | (601) | 330 | (271) | (626) |
| Net income (loss) | $ 65,853 | $ (60,370) | $ 5,484 | $ 49,666 |
| Income (loss) per unit - basic and diluted | $ 1.51 | $ (1.39) | $ 0.13 | $ 1.25 |
| Weighted average number of units used in computing net income (loss) per unit | ||||
| Basic | 43,563 | 43,529 | 43,546 | 39,646 |
| Diluted | ||||
| 43,563 | 43,529 | 43,549 | 39,646 | |
| LEGACY RESERVES LP | |
| CONDENSED CONSOLIDATED BALANCE SHEET (UNAUDITED) | |
| (dollars in thousands) | |
| June 30, 2011 | |
| ASSETS | |
| Current assets: | |
| Cash and cash equivalents | $ 7,632 |
| Accounts receivable, net: | |
| Oil and natural gas | 34,628 |
| Joint interest owners | 16,430 |
| Other | 291 |
| Fair value of derivatives | 4,681 |
| Prepaid expenses and other current assets | 4,993 |
| Total current assets | 68,655 |
| Oil and natural gas properties, at cost: | |
| Proved oil and natural gas properties, at cost, using the successful efforts method of accounting | 1,289,724 |
| Unproved properties | 12,543 |
| Accumulated depletion, depreciation and amortization | (383,197) |
| 919,070 | |
| Other property and equipment, net of accumulated depreciation and amortization of $2,987 | 2,798 |
| Deposit on pending acquisition | 132 |
| Operating rights, net of amortization of $2,781 | 4,236 |
| Fair value of derivatives | 293 |
| Other assets, net of amortization of $5,619 | 7,364 |
| Investment in equity method investee | 216 |
| Total assets | $ 1,002,764 |
| LIABILITIES AND UNITHOLDERS' EQUITY | |
| Current liabilities: | |
| Accounts payable | $ 5,180 |
| Accrued oil and natural gas liabilities | 48,307 |
| Fair value of derivatives | 21,677 |
| Asset retirement obligation | 18,700 |
| Other | 7,803 |
| Total current liabilities | 101,667 |
| Long-term debt | 405,000 |
| Asset retirement obligation | 96,053 |
| Fair value of derivatives | 46,884 |
| Other long-term liabilities | 1,338 |
| Total liabilities | 650,942 |
| Commitments and contingencies | |
| Unitholders' equity: | |
| Limited partners' equity - 43,566,497 units issued and outstanding at June 30, 2011 | 351,724 |
| General partner's equity (approximately 0.05%) | 98 |
| Total unitholders' equity | 351,822 |
| Total liabilities and unitholders' equity | $ 1,002,764 |
| LEGACY RESERVES LP | ||||
| SELECTED FINANCIAL AND OPERATING DATA | ||||
| Three Months Ended | Six Months Ended | |||
| June 30, | March 31, | June 30, | ||
| 2011 | 2011 | 2011 | 2010 | |
| (In thousands, except per unit data) | ||||
| Revenues: | ||||
| Oil sales | $ 73,569 | $ 59,265 | $ 132,834 | $ 79,378 |
| Natural gas liquid sales | 4,722 | 4,250 | 8,972 | 7,182 |
| Natural gas sales | 14,544 | 9,253 | 23,797 | 14,738 |
| Total revenue | $ 92,835 | $ 72,768 | $ 165,603 | $ 101,298 |
| Expenses: | ||||
| Oil and natural gas production | $ 20,982 | $ 21,497 | $ 42,479 | $ 30,124 |
| Ad valorem taxes | $ 2,456 | $ 2,260 | $ 4,716 | $ 2,738 |
| Total oil and natural gas production including ad valorem taxes | $ 23,438 | $ 23,757 | $ 47,195 | $ 32,862 |
| Production and other taxes | $ 5,533 | $ 4,357 | $ 9,890 | $ 5,873 |
| General and administrative | $ 4,455 | $ 6,358 | $ 10,813 | $ 8,808 |
| Depletion, depreciation, amortization and accretion | $ 22,146 | $ 19,560 | $ 41,706 | $ 29,181 |
| Realized commodity derivative settlements: | ||||
| Realized gain (loss) on oil derivatives | $ (8,852) | $ (1,140) | $ (9,992) | $ 4,191 |
| Realized loss on natural gas liquid derivatives | $ -- | $ -- | $ -- | $ (39) |
| Realized gain on natural gas derivatives | $ 2,565 | $ 2,816 | $ 5,381 | $ 4,819 |
| Production: | ||||
| Oil (MBbls) | 759 | 676 | 1,435 | 1,084 |
| Natural gas liquids (Mgals) | 3,456 | 3,317 | 6,773 | 6,710 |
| Natural gas (MMcf) | 2,248 | 1,601 | 3,849 | 2,466 |
| Total (MBoe) | 1,216 | 1,022 | 2,238 | 1,655 |
| Average daily production (Boe/d) | 13,363 | 11,356 | 12,365 | 9,144 |
| Average sales price per unit (excluding commodity derivatives): | ||||
| Oil price per barrel | $ 96.93 | $ 87.67 | $ 92.57 | $ 73.23 |
| Natural gas liquid price per gallon | $ 1.37 | $ 1.28 | $ 1.32 | $ 1.07 |
| Natural gas price per Mcf | $ 6.47 | $ 5.78 | $ 6.18 | $ 5.98 |
| Combined (per Boe) | $ 76.34 | $ 71.20 | $ 74.00 | $ 61.21 |
| Average sales price per unit (including realized commodity derivative settlements): | ||||
| Oil price per barrel | $ 85.27 | $ 85.98 | $ 85.60 | $ 77.09 |
| Natural gas liquid price per gallon | $ 1.37 | $ 1.28 | $ 1.32 | $ 1.06 |
| Natural gas price per Mcf | $ 7.61 | $ 7.54 | $ 7.58 | $ 7.93 |
| Combined (per Boe) | $ 71.17 | $ 72.84 | $ 71.94 | $ 66.63 |
| NYMEX oil index prices per barrel: | ||||
| Beginning of Period | $ 106.72 | $ 91.38 | $ 91.38 | $ 79.36 |
| End of Period | $ 95.42 | $ 106.72 | $ 95.42 | $ 75.63 |
| NYMEX gas index prices per Mcf: | ||||
| Beginning of Period | $ 4.39 | $ 4.41 | $ 4.41 | $ 5.57 |
| End of Period | $ 4.37 | $ 4.39 | $ 4.37 | $ 4.62 |
| Average unit costs per Boe: | ||||
| Oil and natural gas production | $ 17.25 | $ 21.03 | $ 18.98 | $ 18.20 |
| Ad valorem taxes | $ 2.02 | $ 2.21 | $ 2.11 | $ 1.65 |
| Production and other taxes | $ 4.55 | $ 4.26 | $ 4.42 | $ 3.55 |
| General and administrative | $ 3.66 | $ 6.22 | $ 4.83 | $ 5.32 |
| Depletion, depreciation, amortization and accretion | $ 18.21 | $ 19.14 | $ 18.64 | $ 17.63 |
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 | Six Months Ended | ||||
| June 30, | March 31, | June 30, | |||
| 2011 | 2011 | 2011 | 2010 | ||
| (dollars in thousands) | |||||
| Net income (loss) | $ 65,853 | $ (60,370) | $ 5,484 | $ 49,666 | |
| Plus: | |||||
| Interest expense | 6,492 | 3,377 | 9,869 | 16,338 | |
| Income tax expense (benefit) | 601 | (330) | 271 | 626 | |
| Depletion, depreciation, amortization and accretion | 22,146 | 19,560 | 41,706 | 29,181 | |
| Impairment of long-lived assets | 144 | 1,047 | 1,191 | 8,387 | |
| Equity in income of partnership | (43) | (29) | (72) | (48) | |
| Unit-based compensation expense | 528 | 1,910 | 2,438 | 1,977 | |
| Unrealized loss (gain) on oil and natural gas derivatives | (41,893) | 77,132 | 35,239 | (41,187) | |
| Adjusted EBITDA | $ 53,828 | $ 42,297 | $ 96,126 | $ 64,940 | |
| Less: | |||||
| Cash interest expense | 4,647 | 4,545 | 9,193 | 7,441 | |
| Cash settlements of LTIP unit awards | 385 | 2,285 | 2,669 | 1,911 | |
| Development capital expenditures | 17,386 | 11,909 | 29,295 | 10,262 | |
| Distributable Cash Flow | $ 31,410 | $ 23,558 | $ 54,969 | $ 45,326 | |
CONTACT: Legacy Reserves LP
Steven H. Pruett, 432-689-5200
President and Chief Financial Officer