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Legacy Reserves LP Announces Fourth Quarter 2012 Results, Annual 2012 Results and 2013 Guidance

Monday, February 25, 2013

Legacy Reserves LP Announces Fourth Quarter 2012 Results, Annual 2012 Results and 2013 Guidance14:12 EST Monday, February 25, 2013MIDLAND, Texas, Feb. 25, 2013 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced annual and fourth quarter results for 2012 as well as financial guidance for 2013. Financial results contained herein are preliminary and subject to the audited financial statements included in Legacy's Form 10-K to be filed on or about February 27, 2013. A summary of selected financial information follows. For consolidated financial statements, please see accompanying tables.  Three Months EndedTwelve Months Ended  December 31,September 30,December 31,  2012201220122011   (dollars in millions) Production (Boe/d)  15,729  14,772  14,811  13,071 Revenue $90.5 $84.2 $346.5 $336.9 Adjusted EBITDA (*) $51.6 $49.5 $197.6 $201.4 Development capital expenditures $19.7 $19.6 $68.2 $71.6 Distributable Cash Flow (*) $24.7 $23.7 $104.5 $107.8 * 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. 2012 highlights include: 13% increase in production to 14,811 Boe/d from 13,071 Boe/d in 2011 primarily due to (i) $635.4 million of acquisitions of producing properties during 2012, which only includes twelve days of production from our $502.6 million Permian Basin acquisition from Concho Resources Inc. ("2012 COG Acquisition"), (ii) a full-year impact of our 2011 acquisitions, and (iii) $68.2 million of development capital expenditures during 2012.    31% increase in year-end proved reserves to 83.2 MMBoe (88% PDP, 68% liquids) compared to 63.4 MMBoe (85% PDP, 68% liquids) as of year-end 2011 primarily driven by a 27.0 MMBoe increase from acquisitions partially offset by a 5.4 MMBoe decrease from production and a 2.4 MMBoe decrease from lower commodity prices.   Adjusted EBITDA of $197.6 million, the second highest in our history despite lower realized commodity prices and higher workover and other unusual well failure expenses. Q4 2012 highlights include: 6% increase in production to 15,729 Boe/d from 14,772 Boe/d in the prior quarter primarily due to $519.8 million of acquisitions during the quarter including twelve days of production (approximately 640 Boe/d for the quarter) from our 2012 COG Acquisition, our development activity in the Wolfberry, and an outstanding horizontal Bone Spring well that began producing in November.   4% increase in Adjusted EBITDA to $51.6 million from $49.5 million during the third quarter.   Ninth consecutive increase in our quarterly distribution, ending the year at $0.57 per unit which represents 3.6% year-over-year growth.   To finance our recent acquisition and prepare for potential future acquisitions, (i) closed our largest equity offering in November providing $218.0 million in net proceeds, (ii) gained first-time access to the high yield market through our $300 million 8% senior notes offering, and (iii) increased our borrowing base for the third time in 2012 to $800 million with a newly-expanded 20-member bank group. Cary D. Brown, Chairman, President and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, commented: "2012 was a landmark year for Legacy, as we closed the largest acquisition in our history on December 20, the $502.6 million acquisition of Permian Basin properties from Concho. These properties are in some of the most prolific fields in the Permian Basin. With the exception of the Lower Abo, these properties provide us with a strong set of mature PDP assets with modest production decline rates as well as a very strong portfolio of proved and unproved drilling locations and developed, non-producing projects. Our integration of this acquisition is going smoothly thus far, and since assuming operations on January 1, our operations group is even more excited about the asset potential they are seeing. "The Concho acquisition helped us set a Company record in proved reserves with 83.2 MMBoe and, despite closing the transaction at the very end of the year, we also set annual and quarterly production records of over 14,800 Boe/d during 2012 and over 15,700 Boe/d during the fourth quarter. We generated Adjusted EBITDA of $197.6 million, the second highest in our history, in the face of challenging Midland-to-Cushing crude oil differentials and unusually high well failure expenses. A market has developed to hedge the Midland-to-Cushing differential and we have now hedged a significant portion of our exposure during 2013. On the development front, we continue to be pleased with our results from our Wolfberry drilling and are excited about the results from our new horizontal Bone Spring well that began producing in November. Due to our acquisitions, strong development results and promising outlook, we increased our distribution every quarter during 2012, resulting in year-over-year distribution growth of 3.6%. We have now increased our distribution for the last nine consecutive quarters. For the year, assuming we had used $50.0 million of our development capital expenditures as maintenance capital expenditures (approximately 25% of our Adjusted EBITDA), our 2012 coverage ratio was 1.11 times. Using $13 million as maintenance capital expenditures (roughly 25% of Adjusted EBITDA) and excluding the impact of the Concho acquisition and our associated year-end capital raises, our fourth quarter distributable cash flow per unit would have been approximately $0.64 per unit, covering our $0.57 distribution by 1.12 times. "Due to our recent strong drilling results and our newly-expanded development inventory, in January our board approved a 2013 capital budget of $90 million. We consider $68 million of our budget to be maintenance capital. With our multi-year, oil-weighted drilling inventory, our recently closed Concho acquisition and our strong ongoing acquisition efforts, we are excited about our opportunities in 2013 and beyond." Dan Westcott, Executive Vice President and Chief Financial Officer, commented, "We are very pleased with our acquisition efforts and growth in 2012. To finance the Concho acquisition, we completed our largest equity offering and issued $300 million of senior notes during the fourth quarter. In addition, our now 20-member bank group redetermined our borrowing base at $800 million. As of February 25, we had $500 million of debt outstanding under our revolving credit facility, giving us approximately $300 of current availability (another Company record) for future acquisitions and development projects. With favorable conditions in the capital markets and ample availability under our credit facility, we look forward to another year of strong results and the pursuit of additional acquisitions."2013 Guidance The following table sets forth certain assumptions being used by Legacy to estimate its anticipated results of operations for 2013. These estimates do not include any acquisitions of additional oil or natural gas properties. In addition, these estimates are based on, among other things, assumptions of capital expenditure levels, current indications of supply and demand for oil and natural gas and current operating and labor costs. The guidance set forth below does not constitute any form of guarantee, assurance or promise that the matters indicated will actually be achieved. The guidance below sets forth management's best estimate based on current and anticipated market conditions and other factors. While we believe that these estimates and assumptions are reasonable, they are inherently uncertain and are subject to, among other things, significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate, as set forth under "Cautionary Statement Relevant to Forward-Looking Information."($ in thousands unless otherwise noted)FY 2013E RangeProduction:       Oil (MBbls) 4,330 -- 4,470 Natural gas liquids (MGal) 13,300 -- 13,750 Natural gas (MMcf) 14,050 -- 14,500 Total (MBoe) 6,988 -- 7,214 Average daily production (Boe/d) 19,146 -- 19,765        Weighted Average NYMEX Differentials: (1)       Oil (per Bbl) ($7.50) -- ($9.00) NGL realization (2) 1.00% -- 1.15% Natural gas (per Mcf) $1.25 -- $1.35        Expenses:       Oil and natural gas production expenses ($/Boe) $18.30 -- $19.20 Ad valorem taxes (% of revenue) 3.25% -- 3.50% Production and other taxes (% of revenue) 6.00% -- 6.50% Cash G&A expenses (3) $25,400 -- $26,650         (1) Based on current NYMEX strip pricing. Excludes the impact of commodity derivatives. Q1 2013 oil differentials are projected to be materially wider ($11.75--$13.50) primarily driven by recent Midland-to-Cushing differentials which have since narrowed considerably.   (2) Represents the projected percentage of WTI crude oil prices divided by 42, as we report NGLs in gallons.   (3) Consistent with our definition of Adjusted EBITDA, these figures exclude LTIP expenses. Cash settlements of LTIP (not included herein) impact Distributable Cash Flow.Annual Financial and Operating Results – 2012 Compared to 2011 Production increased 13% to 14,811 Boe/d from 13,071 Boe/d primarily due to (i) $635.4 million of acquisitions of producing properties during 2012, which only includes twelve days of production from our 2012 COG Acquisition, (ii) a full-year impact of our $136.7 million of acquisitions of producing properties during 2011, and (iii) $68.2 million of development capital expenditures during 2012 which was the second highest annual total in our history and was primarily focused on our Wolfberry locations as well as major workovers in the Permian Basin and Wyoming. By commodity, our daily oil production increased by 13% in 2012 due to acquisitions and oil-focused development projects. Our daily natural gas production increased by 17% in 2012 due primarily to the full-year impact during 2012 of our 2011 acquisitions which were natural gas-weighted and, to a lesser extent, production from our 2012 acquisitions and development activities, as the Wolfberry play primarily produces oil but also a significant amount of casinghead natural gas, which is rich in natural gas liquids ("NGL"). Daily NGL production was flat (+0.1%) in 2012.   Average realized prices, excluding commodity derivatives settlements, were $63.91 per Boe in 2012, down 9% from $70.61 per Boe in 2011. Average realized oil prices decreased 4% to $85.78 per Bbl in 2012 from $89.62 per Bbl in 2011. This decrease of $3.84 per Bbl is primarily attributable to an increased weighted-average oil differential of $2.75 per Bbl as well as a slightly lower weighted-average West Texas Intermediate ("WTI") crude oil price. This increase in our oil differential was driven largely by the record increase in the Midland-to-Cushing/WTI differential, which averaged approximately $2.99 per Bbl in 2012 compared to $0.50 per Bbl in 2011. In addition, average realized natural gas prices decreased 28% to $4.38 per Mcf in 2012 from $6.05 per Mcf in 2011. Our average realized natural gas prices are favorably impacted by the NGL content in our Permian Basin natural gas. Our lower realized natural gas price reflects a lower weighted-average Henry Hub natural gas price, which decreased by approximately $1.24 per MMBtu in 2012, as well as a lower, positive differential in 2012 that reflects the lower average prices of the NGL content in our Permian Basin natural gas. Finally, our average realized NGL price decreased 23% to $1.00 per gallon in 2012 from $1.30 per gallon in 2011.   Production expenses, excluding ad valorem taxes, increased 18% to $103.4 million in 2012 from $87.6 million in 2011. On an average cost per Boe basis, production expenses increased 4% to $19.08 per Boe in 2012 from $18.37 per Boe in 2011. Production expenses increased primarily because of (i) $5.1 million related to increases in workover and other unusual well failure expenses due to both increases in number of incidents as well as average cost per job, and (ii) production expenses from our acquisitions, including $0.8 million for the twelve days of activity related to the 2012 COG Acquisition.    Legacy's general and administrative expenses excluding Long-Term Incentive Plan ("LTIP") compensation expense increased to $21.0 million from $19.1 million. The $1.9 million increase stems from a $3.3 million increase from salaries due to the hiring of additional personnel commensurate with the growth in our asset base, partially offset by lower acquisition-related costs of $1.3 million in 2012. Legacy's total general and administrative expenses were $24.5 million and $23.1 million for 2012 and 2011, respectively. In addition to the factors above, Legacy's unit-based/LTIP compensation was $0.5 million lower in 2012 due to decreases in our unit price between December 31, 2011 and December 31, 2012.   Cash settlements received on our commodity derivatives during 2012 were $5.9 million, as the $16.1 million received on our natural gas hedges was partially offset by $10.2 million paid on our oil hedges. This $5.9 million in cash settlements received compared to $0.6 million received during 2011. Our production was 68% hedged in 2012 compared to 71% hedged in 2011.   Development capital expenditures decreased to $68.2 million in 2012 from $71.6 million in 2011, as we continued with our one-rig Wolfberry operated drilling program for most of 2012, drilled our first new horizontal Bone Spring well in late 2012, and increased our capital workover activity in the Permian Basin and Wyoming relative to 2011. Our non-operated capital expenditures were 23% of our total capital expenditures in 2012 as compared to 25% in 2011.2012 Financial and Operating Results – Fourth Quarter Compared to Third Quarter Production increased by 6% to 15,729 Boe/d compared to 14,772 Boe/d in the prior quarter primarily due to recent acquisitions including twelve days of production (approximately 640 Boe/d for the quarter) from our 2012 COG Acquisition, our development in the Wolfberry, and an outstanding horizontal Bone Spring well that began producing in November. Production in the fourth quarter continued to be hampered by high pressures in natural gas gathering lines in the Permian Basin primarily due to extensive development in the area. In addition, natural gas and NGL production was down in the Texas Panhandle in the fourth quarter due to plant downtime.   Average realized prices, excluding commodity derivatives settlements, were $62.51 per Boe in the fourth quarter, up 1% from $61.95 per Boe in the third quarter. Average realized oil prices decreased by 3% to $80.69 per Bbl in the fourth quarter from $83.54 per Bbl in the third quarter. This decrease was attributable to a drop in average WTI crude oil prices, as an increase in the Midland-to-Cushing differential was offset by a significant decrease in our Rockies differentials during the fourth quarter. In addition, average realized natural gas prices increased 15% to $4.71 per Mcf in the fourth quarter from $4.10 per Mcf in the third quarter and average realized NGL prices increased 15% to $1.05 per gallon in the fourth quarter from $0.91 per gallon in the third quarter.   Production expenses, excluding taxes, remained flat at $28.3 million in the fourth quarter from $28.2 million in the third quarter, as production expenses associated with recent acquisitions, including $0.8 million associated with the twelve days of activity from the 2012 COG Acquisition, were offset by lower workover and other well failure related expenses, which were still roughly $1.0 million above normal levels but approximately $1.1 million lower than those expenses during the third quarter. Production expenses per Boe decreased 6% to $19.59 per Boe in the fourth quarter from $20.76 per Boe in the third quarter.   Legacy's general and administrative expenses excluding unit-based/LTIP compensation expense totaled $6.0 million during the fourth quarter compared to $4.9 million in the third quarter. This increase was attributable to acquisition-related and year-end compliance and other costs. Legacy's total general and administrative expenses were $5.9 million during the fourth quarter compared to $7.0 million during the third quarter. LTIP expense decreased to a $0.1 million benefit in the fourth quarter compared to a $2.1 million expense in the third quarter primarily due to fluctuations in our unit price.   Cash settlements received on our commodity derivatives during the fourth quarter were $3.9 million compared to $6.1 million received during the third quarter. The decline in WTI crude oil prices between September and December resulted in a negative one-month lag effect on our crude oil hedges, with our cash settlements received being approximately $1.4 million lower during the fourth quarter. In contrast, this lag effect caused our cash settlements received on our oil hedges to be approximately $2.7 million higher during the third quarter due to rising oil prices during that period.   Development capital expenditures were relatively flat at $19.7 million in the fourth quarter compared to $19.6 million in the third quarter, making it the second highest quarter for development capital expenditures in Legacy's history. Our development capital expenditures in the fourth quarter included our Wolfberry drilling program as well as an operated horizontal Bone Spring well that began producing in November. The results of our Wolfberry drilling program continue to meet or exceed expectations, and the results of our horizontal Bone Spring well have clearly exceeded expectations. Commodity Derivatives Contracts We have entered into the following oil and natural gas derivatives contracts, including swaps and three-way collars, to help mitigate the risk of changing commodity prices. As of February 25, 2013, we had entered into derivatives agreements to receive average NYMEX WTI crude oil and Waha, ANR-Oklahoma, and CIG-Rockies natural gas prices as summarized below starting with January 2013 through December 2017: Crude Oil (WTI):Calendar Year Volumes (Bbls)Average Price per BblPrice Range per Bbl 2013  2,155,693 $90.92 $80.10 -- $108.65 2014  1,520,764 $91.54 $87.50 -- $103.75 2015  545,351 $91.98 $88.50 -- $100.20 2016  228,600 $87.94 $86.30 -- $99.85 2017  182,500 $84.75 $84.75 We have also entered into multiple NYMEX WTI crude oil derivative three-way collar contracts as follows:Calendar Year Volumes (Bbls)Average Short Put PriceAverage Long Put PriceAverage Short Call Price 2013  1,228,170 $65.53 $90.97 $105.85 2014  1,453,880 $65.54 $90.73 $110.65 2015  1,308,500 $64.67 $89.67 $112.21 2016  621,300 $63.37 $88.37 $106.40 2017  72,400 $60.00 $85.00 $104.20 Additionally, we have entered into swaps for the Midland-to-Cushing/WTI crude oil differential with the following attributes:Time Period Volumes (Bbls)Average Price per BblPrice Range per Bbl Q1 2013  180,000 ($1.25) ($1.25) Q2 - Q4 2013  2,200,000 ($1.47) $(1.25) -- $(1.75) Natural Gas (WAHA, ANR-Oklahoma and CIG-Rockies hubs):Calendar Year Volumes (MMBtu)Average Price per MMBtuPrice Range per MMBtu 2013  9,240,654 $4.31 $3.18 -- $6.89 2014  7,431,254 $4.34 $3.61 -- $6.47 2015  1,339,300 $5.65 $5.14 -- $5.82 2016  219,200 $5.30 $5.30 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 2012 Form 10-K which will be filed on or about February 27, 2013. Conference Call As announced on January 22, 2013, Legacy will host an investor conference call to discuss Legacy's results on Tuesday, February 26, 2013 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 Saturday, March 2, 2013, by dialing 855-859-2056 or 404-537-3406 and entering replay code 92534708. 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. 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 EndedTwelve Months Ended  December 31,September 30,December 31,  2012201220122011  (In thousands, except per unit data) Revenues:         Oil sales  $ 74,157  $ 70,173  $ 286,254  $ 264,473 Natural gas liquids (NGL) sales  3,850  3,492  14,592  18,888 Natural gas sales  12,448  10,531  45,614  53,524 Total revenues  90,455  84,196  346,460  336,885           Expenses:         Oil and natural gas production  30,929  30,728  112,951  96,914 Production and other taxes  5,737  5,137  20,778  20,329 General and administrative  5,922  6,993  24,526  23,084 Depletion, depreciation, amortization and accretion  29,102  24,833  102,144  88,178 Impairment of long-lived assets  14,510  7,277  37,066  24,510 (Gain) loss on disposal of assets  568  260  (2,496)  (625) Total expenses  86,768  75,228  294,969  252,390           Operating income  3,687  8,968  51,491  84,495           Other income (expense):         Interest income  5  3  16  15 Interest expense  (6,003)  (5,285)  (20,260)  (18,566) Equity in income of partnership  23  30  111  138 Realized and unrealized net gains (losses) on commodity derivatives  4,409  (27,177)  38,493  6,857 Other  (31)  (51)  (118)  152 Income (loss) before income taxes  2,090  (23,512)  69,733  73,091           Income tax expense  (218)  (54)  (1,096)  (1,030)           Net income (loss)  $ 1,872  $ (23,566)  $ 68,637  $ 72,061 Income (loss) per unit --         basic and diluted  $ 0.04  $ (0.49)  $ 1.40  $ 1.63           Weighted average number of units used in computing net income (loss) per unit --     Basic  52,416  47,869  48,991  44,093 Diluted  52,454  47,869  48,991  44,112            LEGACY RESERVES LPCONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)(dollars in thousands)        December 31,  20122011ASSETS     Current assets:     Cash and cash equivalents  $ 3,509  $ 3,151 Accounts receivable, net:     Oil and natural gas  37,547  35,489 Joint interest owners  27,851  10,299 Other  551  204 Fair value of derivatives  15,158  7,117 Prepaid expenses and other current assets  3,294  3,525 Total current assets  87,910  59,785       Oil and natural gas properties, at cost:     Proved oil and natural gas properties using the successful efforts method of accounting  2,078,961  1,389,326 Unproved properties  65,968  20,063 Accumulated depletion, depreciation, amortization and impairment  (573,003)  (450,060)    1,571,926  959,329       Other property and equipment, net of accumulated depreciation and amortization of $4,618 and $3,530, respectively  2,646  3,310 Operating rights, net of amortization of $3,531 and $3,034, respectively  3,486  3,983 Fair value of derivatives  15,834  10,188 Other assets, net of amortization of $7,909 and $6,337, respectively  7,804  6,611 Investment in equity method investee  393  282 Total assets  $ 1,689,999  $ 1,043,488      LIABILITIES AND UNITHOLDERS' EQUITY     Current liabilities:     Accounts payable  $ 1,822  $ 3,286 Accrued oil and natural gas liabilities  50,162  45,351 Fair value of derivatives  10,801  18,905 Asset retirement obligation  29,501  20,262 Other  11,437  9,646 Total current liabilities  103,723  97,450       Long-term debt  775,838  337,000 Asset retirement obligation  132,682  100,012 Fair value of derivatives  5,590  18,897 Other long-term liabilities  1,886  1,794 Total liabilities  1,019,719  555,153       Commitments and contingencies     Unitholders' equity:     Limited partners' equity - 57,038,942 and 47,801,682 units issued and outstanding, respectively  670,183  488,264 General partner's equity (approximately 0.03% and 0.04%, respectively)  97  71 Total unitholders' equity  670,280  488,335 Total liabilities and unitholders' equity  $ 1,689,999  $ 1,043,488                    LEGACY RESERVES LPSELECTED FINANCIAL AND OPERATING DATA            Three Months EndedTwelve Months Ended  December 31,September 30,December 31,  2012201220122011  (In thousands, except per unit data) Revenues:         Oil sales  $ 74,157  $ 70,173  $ 286,254  $ 264,473 Natural gas liquids sales  3,850  3,492  14,592  18,888 Natural gas sales  12,448  10,531  45,614  53,524 Total revenues  $ 90,455  $ 84,196  $ 346,460  $ 336,885           Expenses:         Oil and natural gas production  $ 28,343  $ 28,207  $ 103,409  $ 87,626 Ad valorem taxes  $ 2,586  $ 2,521  $ 9,542  $ 9,288 Total oil and natural gas production including ad valorem taxes  $ 30,929  $ 30,728  $ 112,951  $ 96,914 Production and other taxes  $ 5,737  $ 5,137  $ 20,778  $ 20,329 General and administrative excluding LTIP  $ 6,046  $ 4,855  $ 20,980  $ 19,063 LTIP expense (benefit)  $ (124)  $ 2,138  $ 3,546  $ 4,021 Total general and administrative  $ 5,922  $ 6,993  $ 24,526  $ 23,084 Depletion, depreciation, amortization and accretion  $ 29,102  $ 24,833  $ 102,144  $ 88,178           Realized commodity derivative settlements:         Realized gains (losses) on oil derivatives  $ 738  $ 2,108  $ (10,211)  $ (11,335) Realized gains on natural gas derivatives  $ 3,146  $ 4,000  $ 16,113  $ 11,972           Production:         Oil (MBbls)  919  840  3,337  2,951 Natural gas liquids (MGal)  3,670  3,821  14,607  14,559 Natural gas (MMcf)  2,643  2,571  10,417  8,842 Total (MBoe)  1,447  1,359  5,421  4,771 Average daily production (Boe/d)  15,729  14,772  14,811  13,071           Average sales price per unit (excluding commodity derivatives):       Oil price (per Bbl)  $ 80.69  $ 83.54  $ 85.78  $ 89.62 Natural gas liquids price (per Gal)  $ 1.05  $ 0.91  $ 1.00  $ 1.30 Natural gas price (per Mcf)  $ 4.71  $ 4.10  $ 4.38  $ 6.05 Combined (per Boe)  $ 62.51  $ 61.95  $ 63.91  $ 70.61           Average sales price per unit (including realized commodity derivative gains/losses):       Oil price (per Bbl)  $ 81.50  $ 86.05  $ 82.72  $ 85.78 Natural gas liquids price (per Gal)  $ 1.05  $ 0.91  $ 1.00  $ 1.30 Natural gas price (per Mcf)  $ 5.90  $ 5.65  $ 5.93  $ 7.41 Combined (per Boe)  $ 65.20  $ 66.45  $ 65.00  $ 70.74           NYMEX oil index prices per Bbl:         Beginning of Period  $ 92.19  $ 84.96  $ 98.83  $ 91.38 End of Period  $ 91.82  $ 92.19  $ 91.82  $ 98.83           NYMEX gas index prices per Mcf:         Beginning of Period  $ 3.32  $ 2.82  $ 2.99  $ 4.41 End of Period  $ 3.35  $ 3.32  $ 3.35  $ 2.99           Average unit costs per Boe:         Oil and natural gas production  $ 19.59  $ 20.76  $ 19.08  $ 18.37 Ad valorem taxes  $ 1.79  $ 1.86  $ 1.76  $ 1.95 Production and other taxes  $ 3.96  $ 3.78  $ 3.83  $ 4.26 General and administrative excluding LTIP  $ 4.18  $ 3.57  $ 3.87  $ 4.00 Total general and administrative  $ 4.09  $ 5.15  $ 4.52  $ 4.84 Depletion, depreciation, amortization and accretion  $ 20.11  $ 18.27  $ 18.84  $ 18.48 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; 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 including the accrual of interest expense related to our senior notes which is paid on a semi-annual basis; Cash income taxes; Cash settlements of LTIP unit awards; and Development capital expenditures (*). * Beginning in the first quarter of 2013, Legacy intends to deduct only maintenance capital expenditures instead of total development capital expenditures in the computation and presentation of Distributable Cash Flow, which will result in the measure of Distributable Cash Flow not being comparable from period to period. 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,  2012201220122011   (dollars in thousands) Net income (loss)  $ 1,872  $ (23,566)  $ 68,637  $ 72,061 Plus:         Interest expense   6,003  5,285  20,260  18,566 Income tax expense  218  54  1,096  1,030 Depletion, depreciation, amortization and accretion  29,102  24,833  102,144  88,178 Impairment of long-lived assets  14,510  7,277  37,066  24,510 (Gain) loss on sale of assets  568  260  (2,496)  (625) Equity in income of partnership  (23)  (30)  (111)  (138) Unit-based compensation expense (benefit)  (124)  2,138  3,546  4,021 Unrealized (gains) losses on oil and natural gas derivatives  (525)  33,285  (32,591)  (6,220)Adjusted EBITDA  $ 51,601  $ 49,536  $ 197,551  $ 201,383           Less:         Cash interest expense  6,991  5,283  21,387  19,044 Cash settlements of LTIP unit awards  184  990  3,555  2,916 Development capital expenditures  19,693  19,565  68,150  71,589Distributable Cash Flow  $ 24,733  $ 23,698  $ 104,459  $ 107,834CONTACT: Legacy Reserves LP Dan Westcott Executive Vice President and Chief Financial Officer (432) 689-5200