The Globe and Mail

Go to the Globe and Mail homepage

Jump to main navigationJump to main content

Press release from GlobeNewswire (a Nasdaq OMX company)

Legacy Reserves LP Announces Second Quarter 2012 Results

Wednesday, August 01, 2012

Legacy Reserves LP Announces Second Quarter 2012 Results13:26 EDT Wednesday, August 01, 2012MIDLAND, Texas, Aug. 1, 2012 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced its second quarter results for 2012. The final unaudited Quarterly Report will be released and filed on or about August 3, 2012. A summary of selected financial information follows. For consolidated financial statements, please see accompanying tables.      Three Months EndedSix Months Ended    June 30,March 31,June 30,    2012201220122011     (dollars in millions)   Production (Boe/d)  14,297  14,440  14,368  12,365   Revenue $79.2 $92.6 $171.8 $165.6   Commodity derivative cash settlements paid ($2.0) ($2.1) ($4.1) ($4.6)   Expenses $75.3 $57.7 $133.0 $110.2   Operating income $3.9 $35.0 $38.8 $55.5   Unrealized gains (losses) on commodity derivatives $86.4 ($21.0) $65.4 ($35.2)   Net income $82.9 $7.4 $90.3 $5.5   Adjusted EBITDA (*) $40.7 $55.2 $95.9 $96.1   Development capital expenditures $16.7 $12.2 $28.9 $29.3   Distributable Cash Flow (*) $19.1 $36.4 $55.5 $55.0       * 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 the second quarter of 2012 compared to the first quarter of 2012 include the following: Production decreased 1% to 14,297 Boe per day in the second quarter from 14,440 Boe per day in the first quarter.  As previously discussed, to stay within our $62 million capital budget and still develop a few of our locations in emerging plays, we chose not to drill any of our Wolfberry locations during March and April. In addition, due to the normal time lag involved in the drilling and completion process, our second quarter results do not include production from our Wolfberry wells that we drilled in May and June. Accordingly, our second quarter production was negatively impacted by the significant natural production declines associated with our Wolfberry drilling, which provided strong initial production rates during the first quarter. Due to our drilling delays, these production declines were not offset by new initial operated production during the second quarter. In addition, high pressures in natural gas gathering lines in the Permian Basin during the second quarter that were caused by normal plant maintenance downtime and extensive development in the area also contributed to our production decline. These factors were largely offset by production from approximately $107.6 million of acquisitions of producing properties during the first half of 2012, including our acquisition of oil properties in North Dakota and Montana for $69.3 million that closed on May 23, as well as production from several successful workovers in Wyoming and the Permian Basin.               Average realized prices, excluding commodity derivatives settlements, were $60.85 per Boe in the second quarter, down 14% from $70.51 per Boe in the first quarter. Average realized oil prices decreased 14% to $83.27 per Bbl in the second quarter from $96.62 per Bbl in the first quarter, as our realized oil prices were impacted not only by a decline of approximately $9.70 per Bbl (9%) in average West Texas Intermediate ("WTI") crude oil prices during the second quarter compared to the first quarter, but also by an increase of approximately $3.65 per Bbl in oil differentials during the second quarter. These increased differentials were primarily driven by a Midland-to-Cushing/WTI differential that averaged approximately $4.90 per Bbl in the second quarter compared to approximately $1.50 per Bbl in the first quarter, or an increase of $3.40 per Bbl. As the refinery downtime issues that were the primary cause of the increased Midland-to-Cushing differential were alleviated, this differential narrowed back to first-quarter levels during the end of the second quarter and early third quarter. In addition, realized natural gas prices decreased 20% to $3.87 per Mcf in the second quarter from $4.81 per Mcf in the first quarter, and average realized NGL prices decreased 9% to $0.97 per gallon in the second quarter from $1.07 per gallon in the first quarter. Our average realized natural gas prices are favorably impacted by the NGL content in our Permian Basin natural gas.              Oil, NGL and natural gas sales, excluding commodity derivatives settlements, were $79.2 million in the second quarter, a decrease of 15% from $92.6 million in the first quarter due to slightly lower production and significantly lower realized commodity prices per Boe. The increased oil differentials during the second quarter decreased our revenues by approximately $2.9 million, including approximately $1.9 million attributable to the increased Midland-to-Cushing differential.   Production expenses, excluding taxes, increased 4% to $23.9 million in the second quarter from $23.0 million in the first quarter due to production expenses associated with recent acquisitions. Production expenses per Boe increased 5% to $18.35 per Boe in the second quarter from $17.49 per Boe in the first quarter.         Legacy's general and administrative expenses were $5.2 million or $3.97 per Boe during the second quarter compared to $6.5 million or $4.91 per Boe during the first quarter.  This decrease was primarily due to lower unit-based compensation expense, which decreased to a benefit of approximately $24,000 during the second quarter from $1.6 million of expense during the first quarter. This decrease in unit-based compensation expense was primarily due to annual awards issued under our long-term incentive plan ("LTIP") during the first quarter as well as a reduction of our LTIP liability and recording of a corresponding compensation benefit due to our unit price falling $3.91 between the end of the first quarter and the end of the second quarter.         Cash settlements paid on our commodity derivatives during the second quarter were $2.0 million compared to $2.1 million paid during the first 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 corresponding volumes are hedged. After WTI crude oil prices averaged approximately $106 per barrel in March 2012, we paid settlements of $3.2 million on our March oil hedges in early April, which impacted our second quarter results. In contrast, after WTI crude oil prices averaged approximately $82 per barrel in June, we received settlements of $2.0 million on our June oil hedges in early July, which will impact our third quarter results. This lag effect on crude oil hedges during a period of rapidly decreasing oil prices caused our cash paid on our oil hedges to be approximately $5.2 million higher during the second quarter. In contrast, this lag effect during a period of increasing prices caused our cash settlements paid on our oil hedges to be approximately $1.6 million lower during the first quarter. We also reported unrealized gains of $86.4 million on our commodity derivatives portfolio during the second quarter, as the impact of decreasing NYMEX oil futures prices from the end of the first quarter until the end of the second quarter was partially offset by an increase in NYMEX natural gas futures prices over the same time frame. As a result of these unrealized gains, our commodity derivatives net liability of $29.5 million at March 31, 2012 was converted to a net asset of $56.9 million at June 30, 2012. In comparison, we reported unrealized losses of $21.0 million on our commodity derivatives portfolio during the first quarter due to increasing oil prices partially offset by declining natural gas prices.      Adjusted EBITDA decreased 26% to $40.7 million during the second quarter from $55.2 million during the first quarter due primarily to lower realized commodity prices (due in part to increased oil differentials), a $5.2 million negative oil hedge lag effect in the second quarter and a $1.6 million positive oil hedge lag effect in the first quarter.  (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 $16.7 million in the second quarter from $12.2 million in the first quarter. In addition to our operated Wolfberry drilling in May and June, we also incurred capital expenditures on several successful workovers in Wyoming and the Permian Basin during the second quarter. Our non-operated capital expenditures also increased from approximately $3 million in the first quarter to approximately $5 million in the second quarter. Both our operated and non-operated capital expenditures in the second quarter were heavily weighted toward the latter half of the quarter and, as such, will not have a material impact on production until the third quarter.           Distributable cash flow decreased to $19.1 million in the second quarter compared to $36.4 million in the first quarter. This decrease was due to significantly lower Adjusted EBITDA, higher development capital expenditures, and slightly higher cash interest expense which were partially offset by a $2.2 million decrease in cash settlements paid on LTIP unit awards.   We generated net income of $82.9 million, or $1.73 per unit, in the second quarter, as unrealized gains of $86.4 million on our commodity derivatives were partially offset by lower realized commodity prices (due in part to increased oil differentials) and a $14.0 million impairment charge on our oil and natural gas properties.  We reported net income of $7.4 million, or $0.15 per unit, in the first quarter, which included unrealized losses of $21.0 million on our commodity derivatives and a $1.3 million impairment charge on our oil and natural gas properties. Cary D. Brown, Chairman, President and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, commented: "During Legacy's second quarter, good operational results and strong acquisition efforts were overshadowed by several factors that negatively impacted our Adjusted EBITDA. Due to WTI average oil prices of approximately $106 per Bbl in March and approximately $82 per Bbl in June, an unusually large negative oil hedge lag effect of $5.2 million burdened our Adjusted EBITDA during the second quarter. In addition, our realized oil prices during the second quarter were impacted by increased average oil differentials ($2.9 million impact) due mostly to a historically high average Midland-to-Cushing differential ($1.9 million impact). These factors, combined with the impact of falling commodity prices on the portion of our quarterly production that was unhedged, were the primary contributors to our decline in Adjusted EBITDA from the first quarter to the second quarter. On a positive note, the refinery downtime issues that were the primary cause of the increased Midland-to-Cushing differential have been alleviated, which has resulted in this differential returning to more normal levels. On the acquisition front, we closed seven acquisitions of producing properties for $105.2 million that we believe will be highly accretive, including our acquisition of oil properties in North Dakota and Montana for $69.3 million that closed on May 23. Our $105.2 million of acquisitions makes the second quarter one of our strongest quarters ever for acquisitions and our best since the fourth quarter of 2010. The production from these acquisitions along with several successful workovers in Wyoming and the Permian Basin helped keep our production relatively flat during the second quarter despite not drilling any of our operated Wolfberry locations during March and April. In addition, we continued to keep our expenses in line, and made larger than expected investments in several attractive non-operated drilling projects during the quarter.  "Overall, our performance over the first half of 2012 was strong, as we generated $95.9 million of Adjusted EBITDA and $55.5 million of distributable cash flow. We look forward to realizing the full impact of our recent acquisitions during the second half of 2012, and we are excited about our pipeline of potential acquisitions as well as our inventory of operated and non-operated development projects. Based on our results over the first half of 2012 and our positive outlook, we increased our quarterly distribution for the seventh consecutive quarter to $0.56 per unit, which will be paid on August 10, 2012. Since the second quarter of 2011, we have increased our quarterly distribution by 3.7%. Finally, during the first half of 2012, we generated distributable cash flow per unit of $1.16, covering our $1.115 distribution by 1.04 times."  James R. Lawrence, Interim Chief Financial Officer, Vice President – Finance and Treasurer, commented, "We are pleased with our results and our strong acquisition efforts during the first half of 2012, as we expect our $107.6 million of acquisitions of producing properties during the first half of 2012 to be immediately and long-term accretive to our distributable cash flow per unit. On August 1, our debt outstanding under our credit facility was $432 million, leaving us with current availability of $133 million. Our current borrowing base of $565 million was redetermined by our 14-member bank group on March 30, and their redetermination calculations included none of our $107.6 million of acquisitions of producing properties. Our next regularly scheduled bank group meeting is in September, and we expect to have our revised borrowing base including our acquisitions on or around October 1."  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 1, 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: Crude Oil (WTI):            AveragePriceCalendar YearVolumes (Bbls)Price per BblRange per Bbl July-December 2012  1,131,571 $89.46 $67.72 - $109.20 2013   1,498,443 $90.10 $80.10 - $108.65 2014  901,014 $92.89 $87.50 - $103.75 2015  362,851 $93.73 $90.50 - $100.20 2016  45,600 $94.53 $91.00 - $99.85         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 August 1, 2012:              Average ShortAverage LongAverage ShortCalendar YearVolumes (Bbls)Put PricePut PriceCall Price July-December 2012  220,800 $68.13 $95.00 $113.54 2013  795,670 $66.24 $91.92 $112.25 2014   1,007,130 $65.78 $91.05 $115.64 2015  1,016,500 $65.48 $90.48 $116.51 2016  438,300 $64.78 $89.78 $110.54 2017  72,400 $60.00 $85.00 $104.20           Additionally, we have entered into a costless collar for NYMEX WTI crude oil with the following attributes:            FloorCeilingCalendar YearVolumes (Bbls)PricePrice July-December 2012  32,800  $ 120.00  $ 156.30         Natural Gas (WAHA, ANR-Oklahoma, and CIG-Rockies hubs):            AveragePriceCalendar YearVolumes (MMBtu)Price per MMBtuRange per MMBtu July-December 2012  3,288,720 $5.10 $2.46 - $8.70 2013  5,430,654 $4.85 $3.23 - $6.89 2014  3,891,254 $4.73 $3.61 - $6.47 2015  1,339,300 $5.65 $5.14 - $5.82 2016  219,200 $5.30 $5.30         Additionally, we have entered into a costless collar for WAHA natural gas with the following attributes:            FloorCeilingCalendar YearVolumes (MMBtu)PricePrice July-December 2012  180,000  $ 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, 2012 Form 10-Q, which will be filed on or about August 3, 2012. Conference Call As announced on July 20, 2012, Legacy will host an investor conference call to discuss Legacy's results on Thursday, August 2, 2012 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 6, 2012, by dialing (855) 859-2056 or (404) 537-3406 and entering replay code 12440391. 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 investors and 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 LPCONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS(UNAUDITED)            Three Months EndedSix Months Ended  June 30,March 31,June 30,  2012201220122011  (In thousands, except per unit data) Revenues:         Oil sales  $ 65,787  $ 76,137  $ 141,925  $ 132,834 Natural gas liquids (NGL) sales  3,524  3,726  7,250  8,972 Natural gas sales  9,851  12,784  22,634  23,797           Total revenues  79,162  92,647  171,809  165,603           Expenses:         Oil and natural gas production  26,406  24,888  51,294  47,195 Production and other taxes  4,687  5,217  9,904  9,890 General and administrative  5,161  6,450  11,611  10,813 Depletion, depreciation, amortization and accretion  25,370  22,839  48,209  41,706 Impairment of long-lived assets  13,978  1,301  15,279  1,191 Gain on disposal of assets   (313)  (3,011)  (3,324)  (645)           Total expenses  75,289  57,684  132,973  110,150           Operating income  3,873  34,963  38,836  55,453           Other income (expense):         Interest income  4  4  8  7 Interest expense  (4,636)   (4,336)  (8,971)  (9,869) Equity in income of partnership  32  26  57  72 Realized and unrealized net gains (losses) on commodity derivatives  84,350  (23,089)  61,261  (39,850) Other  (68)  32  (36)  (58)           Income before income taxes  83,555  7,600  91,155  5,755           Income tax expense  (613)  (211)  (824)  (271)           Net income  $ 82,942  $ 7,389  $  90,331  $ 5,484           Income per unit --         basic and diluted  $ 1.73  $ 0.15  $ 1.89  $ 0.13           Weighted average number of units used in computing net income per unit         Basic  47,850  47,802  47,826  43,546           Diluted  47,850  47,848  47,826  43,549  LEGACY RESERVES LPCONDENSED CONSOLIDATED BALANCE SHEET (UNAUDITED) (dollars in thousands)  June 30,  2012ASSETS Current assets:   Cash and cash equivalents  $ 3,582 Accounts receivable, net:   Oil and natural gas  30,445 Joint interest owners  11,558 Other  443 Fair value of derivatives  24,513 Prepaid expenses and other current assets  3,530     Total current assets  74,071     Oil and natural gas properties, at cost:   Proved oil and natural gas properties using the successful efforts method of accounting  1,516,223 Unproved properties  26,215 Accumulated depletion, depreciation, amortization and impairment  (500,684)        1,041,754     Other property and equipment, net of accumulated depreciation and amortization of $3,992  2,718 Operating rights, net of amortization of $3,282  3,734 Fair value of derivatives  33,328 Other assets, net of amortization of $7,090  6,151 Investment in equity method investee  339     Total assets  $ 1,162,095    LIABILITIES AND UNITHOLDERS' EQUITY Current liabilities:   Accounts payable  $ 2,536 Accrued oil and natural gas liabilities  46,394 Fair value of derivatives  5,168 Asset retirement obligation  21,267 Other  6,652     Total current liabilities  82,017 Long-term debt  439,000 Asset retirement obligation  104,889 Fair value of derivatives  7,062 Other long-term liabilities  2,165     Total liabilities  635,133 Commitments and contingencies   Unitholders' equity:   Limited partners' equity - 47,868,942 units issued and outstanding  526,856 General partner's equity (approximately 0.04%)  106     Total unitholders' equity   526,962     Total liabilities and unitholders' equity  $ 1,162,095    LEGACY RESERVES LP  SELECTED FINANCIAL AND OPERATING DATA      Three Months EndedSix Months Ended    June 30,March 31,June 30,    2012201220122011    (In thousands, except per unit data)   Revenues:           Oil sales  $ 65,787  $ 76,137  $ 141,925  $ 132,834   Natural gas liquids sales  3,524  3,726  7,250  8,972   Natural gas sales  9,851  12,784  22,634  23,797               Total revenues  $ 79,162  $ 92,647  $ 171,809  $ 165,603               Expenses:           Oil and natural gas production  $ 23,877  $ 22,983  $ 46,859  $ 42,479   Ad valorem taxes  $ 2,529  $  1,905  $ 4,435  $ 4,716               Total oil and natural gas production including ad valorem taxes  $ 26,406  $ 24,888  $ 51,294  $ 47,195               Production and other taxes  $ 4,687  $ 5,217  $ 9,904  $ 9,890   General and administrative  $ 5,161  $ 6,450  $ 11,611  $ 10,813   Depletion, depreciation, amortization and accretion  $ 25,370  $ 22,839  $ 48,209  $ 41,706               Realized commodity derivative settlements:           Realized losses on oil derivatives  $ (6,855)  $ (6,203)  $ (13,057)  $ (9,992)   Realized gains on natural gas derivatives  $ 4,817  $ 4,150  $ 8,967  $ 5,381               Production:           Oil (MBbls)  790  788  1,578  1,435   Natural gas liquids (MGal)  3,626  3,490  7,116  6,773   Natural gas (MMcf)  2,545  2,658  5,203  3,849   Total (MBoe)  1,301  1,314  2,615  2,238   Average daily production (Boe/d)  14,297  14,440  14,368  12,365               Average sales price per unit (excluding commodity derivatives):           Oil price (per Bbl)  $ 83.27  $ 96.62  $ 89.94  $ 92.57   Natural gas liquids price (per Gal)  $ 0.97  $ 1.07  $ 1.02  $  1.32   Natural gas price (per Mcf)  $ 3.87  $ 4.81  $ 4.35  $ 6.18   Combined (per Boe)  $ 60.85  $ 70.51  $ 65.70  $ 74.00               Average sales price per unit (including realized commodity derivative gains/losses):           Oil price (per Bbl)  $ 74.60  $ 88.75  $ 81.67  $ 85.60   Natural gas liquids price (per Gal)  $ 0.97  $ 1.07  $ 1.02  $ 1.32   Natural gas price (per Mcf)  $ 5.76  $ 6.37  $ 6.07  $ 7.58   Combined (per Boe)  $ 59.28  $ 68.95  $ 64.14  $ 71.94               NYMEX oil index prices per Bbl:           Beginning of Period  $ 103.02  $ 98.83  $ 98.83  $ 91.38   End of Period  $ 84.96  $ 103.02  $ 84.96  $ 95.42               NYMEX gas index prices per Mcf:           Beginning of Period  $ 2.13  $ 2.99  $ 2.99  $ 4.41   End of Period  $ 2.82  $ 2.13  $ 2.82  $ 4.37               Average unit costs per Boe:           Oil and natural gas production  $ 18.35  $ 17.49  $ 17.92  $ 18.98   Ad valorem taxes  $ 1.94  $ 1.45  $  1.70  $ 2.11   Production and other taxes  $ 3.60  $ 3.97  $ 3.79  $ 4.42   General and administrative  $ 3.97  $ 4.91  $ 4.44  $ 4.83   Depletion, depreciation, amortization and accretion  $ 19.50  $ 17.38  $ 18.44  $ 18.64   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. 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 (benefit) 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:     Three Months Ended Six Months Ended  June 30,March 31,June 30,  2012201220122011   (dollars in thousands) Net income  $ 82,942  $ 7,389  $ 90,331  $ 5,484 Plus:         Interest expense  4,636  4,336  8,971  9,869 Income tax expense  613  211  824  271 Depletion, depreciation, amortization and accretion  25,370  22,839  48,209  41,706 Impairment of long-lived assets  13,978  1,301  15,279  1,191 Gain on sale of assets   (349)  (3,488)  (3,837)  --  Equity in income of partnership  (32)  (26)  (57)  (72) Unit-based compensation expense (benefit)   (24)  1,557  1,532  2,438 Unrealized (gains) losses on oil and natural gas derivatives  (86,388)  21,036  (65,351)  35,239Adjusted EBITDA  $ 40,746  $ 55,155  $ 95,901  $ 96,126           Less:         Cash interest expense  4,859  4,254  9,113  9,193 Cash settlements of LTIP unit awards   112  2,268  2,381  2,669 Development capital expenditures  16,693  12,200  28,892  29,295Distributable Cash Flow  $ 19,082  $ 36,433  $ 55,515  $ 54,969CONTACT: Legacy Reserves LP James R. Lawrence Interim Chief Financial Officer, Vice President - Finance and Treasurer 432-689-5200