Legacy Reserves LP Announces Second Quarter 2013 Results MIDLAND, Texas, Aug. 5, 2013 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced second quarter results for 2013. Financial results contained herein are preliminary and subject to the final, unaudited financial statements included in Legacy's Form 10-Q to be filed on or about August 7, 2013. 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, 2013 2013 2013 2012 (dollars in millions) Production (Boe/d) 19,516 19,711 19,613 14,368 Revenue $118.4 $108.9 $227.3 $171.8 Net Income (Loss) $21.8 ($6.7) $15.0 $90.3 Adjusted EBITDA (*) $67.9 $64.4 $132.3 $96.4 Distributable Cash Flow $38.8 $34.9 $73.7 $56.0 (*) * 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. Q2 2013 highlights include: *Production decreased 1% to 19,516 Boe/d, as the impact of extensive third-party plant downtime and natural gas line pressure issues in the Permian Basin was partially offset by production from new development projects in other parts of the Permian Basin and improved production in the Texas Panhandle due to relieved Q1 infrastructure issues. *We generated $118.4 million of revenue and a record $67.9 million of Adjusted EBITDA representing increases of approximately 9% and 6%, respectively, over results in the prior quarter.A key driver of these improvements was improved oil differentials in the Permian Basin and Rocky Mountain regions. *After deducting $17.0 million of maintenance capital expenditures, we generated $38.8 million of Distributable Cash Flow or $0.68 per unit, representing an 11% increase over Q1. *We announced a $0.58 per unit quarterly distribution, marking our 11^th consecutive quarterly increase and resulting in 3.6% year-over-year growth.Our quarterly distribution is covered by our Distributable Cash Flow by 1.17 times. Cary D. Brown, Chairman, President and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, commented: "Legacy produced outstanding results during the second quarter generating record Adjusted EBITDA of $67.9 million and Distributable Cash Flow of $38.8 million.Despite third-party plant downtime in the Permian Basin that curtailed production from several of our oil-weighted properties, we produced over 19,500 Boe/d.Every quarter presents new challenges, and once again our team at Legacy handled these challenges well and produced strong results for our unitholders. Our integration of the Concho acquisition has gone well.We continue to be very pleased with the results from these assets, which produced approximately 5,000 Boe/d during the second quarter despite plant downtime issues in the Permian. "While quarter-over-quarter WTI prices stayed relatively flat, our company-wide oil differential improved by approximately $9.00 per barrel during the second quarter as both the Permian and the Rockies regions improved to levels inside of their historical norms and above our expectations.We expect these differentials to be at or around normal levels for the remainder of 2013, with company-wide oil differentials of $5.25-$6.25 per barrel.Natural gas realizations during the first half of the year were negatively impacted by infrastructure issues and declining NGL prices.We currently expect second-half 2013 positive natural gas differentials of $0.90-$1.00 per Mcf. "On the development front, we continue to be pleased with our program that is focused on oil-weighted projects in the Permian Basin.Our results from our operated Wolfberry drilling program remain solid, and we continue to participate in several attractive non-operated drilling projects, including a horizontal Bone Spring well in which we own a 50% working interest.We are excited about the second half of 2013, as our development pace will accelerate to include the drilling of two operated horizontal Bone Spring wells along with our drilling in the Wolfberry. "We are pleased with our year-to-date acquisitions which total approximately $90 million of oil-weighted producing properties at attractive metrics.We have evaluated and are continuing to evaluate a strong pipeline of acquisitions of various sizes in all of our core areas, and hope to expand our acquisitions in the second half of the year. "Based on these strong financial and operational results as well as our positive outlook, we increased our distribution for the 11^th consecutive quarter to $0.58 per unit, resulting in year-over-year distribution growth of 3.6%.For the quarter, we generated Distributable Cash Flow of $38.8 million or $0.68 per unit, covering our second quarter distribution by 1.17 times." Dan Westcott, Executive Vice President and Chief Financial Officer, commented, "We are very pleased with our strong financial and operational results during the second quarter.On May 28, we closed a $250 million private offering of 6.625% senior notes due in 2021.With this opportunistic financing, we were able to access unsecured long-term capital at very attractive rates that will provide us with greater liquidity to pursue our acquisition and development plans.In accordance with the provisions of our credit agreement, our borrowing base was automatically reduced from $800 million to $737.5 million upon the closing of our senior notes offering.As of August 5, we had $311 million of debt outstanding under our revolving credit facility, giving us a record of approximately $426 million of current availability. Given this availability, our recent performance, and our expectations from our recent $90 million of acquisitions, we are looking forward to the second half of the year and executing on our objectives." 2013 Financial and Operating Results – Second Quarter Compared to First Quarter *Production decreased 1% to 19,516 Boe/d, as extensive third-party plant downtime and natural gas line pressure issues in the Permian Basin had a significant impact on production from several of our oil-weighted properties, including extended periods of shut-in production on some properties.This impact was partially offset by strong production from new development projects in other parts of the Permian Basin, improved natural gas production from other properties in the Permian Basin, and significantly improved production in the Texas Panhandle due to relieved Q1 infrastructure issues.We generated approximately 5,000 Boe/d of production from our Permian Basin acquisition from Concho Resources Inc. ("2012 COG Acquisition") compared to approximately 5,250 Boe/d in the first quarter.These properties continue to outperform our expectations even though production from a number of major oil-weighted properties, including our Lower Abo, Deep Rock, Fullerton and Shafter Lake properties, were significantly impacted by plant downtime during the quarter. *Average realized prices, excluding commodity derivatives settlements, were $66.66 per Boe, up 9% from $61.37 per Boe in the first quarter.Average realized oil prices increased 11% to $89.85 per Bbl from $81.11 per Bbl in the first quarter.While average West Texas Intermediate ("WTI") crude oil prices were essentially flat between the second and first quarters, crude oil differentials in the Permian Basin and Rocky Mountain regions improved significantly, resulting in improved company-wide crude oil differential of approximately $9.02 per Bbl.Most notably, with several refineries returning to production and the addition of new takeaway capacity, the Midland-to-Cushing/WTI differential decreased to approximately $0.16 per barrel in the second quarter from $7.70 per barrel in the first quarter.Average realized natural gas prices increased 11% to $4.76 per Mcf from $4.28 per Mcf in the first quarter due to an improvement in dry gas prices that was partially offset by a reduction in the positive differential to Henry Hub prices in the second quarter that reflects further curtailment of a portion of our NGL-rich natural gas production as well as lower NGL prices in the Permian Basin.Since NGLs are embedded in the value of our Permian Basin natural gas, the inclusion of a lower amount and lower prices of such NGLs had a negative effect on our average realized natural gas price.Average realized prices on our separately reported NGLs decreased 18% to $0.95 per gallon in the second quarter from $1.16 per gallon in the first quarter. *Production expenses, excluding ad valorem taxes, increased 6% to $34.3 million ($19.29 per Boe) from $32.4 million ($18.26 per Boe) in the first quarter due to higher workover and various other expenses, including some continuing remedial workovers on the 2012 COG Acquisition properties. *Legacy's general and administrative expenses excluding unit-based/LTIP compensation expense totaled $5.7 million compared to $5.3 million in the first quarter.This was mostly attributable to the hiring of additional personnel to help us more efficiently manage our larger asset base.Legacy's total general and administrative expenses were $7.1 million compared to $6.3 million during the first quarter, as LTIP expense increased to $1.3 million in the second quarter compared to $1.0 million in the first quarter. *Cash settlements paid on our commodity derivatives were $1.4 million compared to $2.6 million received during the first quarter.The increase in WTI crude oil prices between March and June resulted in a positive one-month lag effect of $0.5 million on our crude oil hedges. *Total development capital expenditures were flat at $19.7 million compared to $19.7 million in the first quarter.Our development capital expenditures were primarily focused on our Wolfberry drilling program where we continue to see solid results.Other activity included attractive non-operated drilling projects in the Permian Basin including the drilling of a horizontal Bone Spring well in which we own a 50% interest, as well as various other development projects mostly in the Permian Basin.Non-operated capital expenditures accounted for approximately 37% of our total development capital for the quarter. We expect our development pace to accelerate in the second half of 2013, including the drilling of two operated horizontal Bone Spring wells along with our drilling in the Wolfberry. Commodity Derivatives Contracts We have entered into the following oil and natural gas derivatives contracts, including swaps, enhanced swaps and three-way collars, to help mitigate the risk of changing commodity prices.As of August 5, 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 July 2013 through December 2018: Crude Oil (WTI): Average Price Calendar Year Volumes (Bbls) Price per Bbl Range per Bbl July-December 2013 1,177,909 $91.80 $80.10 - $103.75 2014 1,776,264 $91.67 $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: Average Short Average Long Average Short Calendar Year Volumes (Bbls) Put Price Put Price Call Price July-December 2013 631,120 $66.34 $91.56 $108.15 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 We have also entered into multiple crude oil derivative enhanced swap contracts as follows: Average Long Average Short Average Swap Calendar Year Volumes (Bbls) Put Price Put Price Price 2015 365,000 $60.00 $80.00 $92.35 2016 183,000 $57.00 $82.00 $91.70 2017 182,500 $57.00 $82.00 $90.85 2018 127,750 $57.00 $82.00 $90.50 Additionally, we have entered into swaps for the Midland-to-Cushing/WTI crude oil differential with the following attributes: Average Price Time Period Volumes (Bbls) Price per Bbl Range per Bbl July-December 2013 1,472,000 ($1.47) $(1.25) - $(1.75) Natural Gas (WAHA, ANR-Oklahoma and CIG-Rockies hubs): Average Price Calendar Year Volumes (MMBtu) Price per MMBtu Range per MMBtu July-December 2013 5,030,302 $4.31 $3.23 - $6.89 2014 8,271,254 $4.32 $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 or natural gas index price. Quarterly Report on Form 10-Q Our consolidated financial statements and related footnotes will be available in our Form 10-Q for the quarter ended June 30, 2013, which will be filed on or about August 7, 2013. Conference Call As announced on July 22, 2013, Legacy will host an investor conference call to discuss Legacy's results on Tuesday, August 6, 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 Tuesday, August 13, 2013, by dialing 855-859-2056 or 404-537-3406 and entering replay code 18067734.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 a master 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 LP CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) Three Months Ended Six Months Ended June 30, March 31, June 30, 2013 2013 2013 2012 (In thousands, except per unit data) Revenues: Oil sales $97,852 $90,357 $188,209 $141,925 Natural gas liquids (NGL) sales 3,161 3,342 6,503 7,250 Natural gas sales 17,373 15,180 32,553 22,634 Total revenues 118,386 108,879 227,265 171,809 Expenses: Oil and natural gas production 37,184 35,351 72,535 51,294 Production and other taxes 6,771 6,927 13,698 9,904 General and administrative 7,064 6,281 13,346 11,611 Depletion, depreciation, 39,113 41,652 80,765 48,209 amortization and accretion Impairment of long-lived assets 20,774 1,743 22,517 15,279 Gain on disposal of assets (46) (219) (265) (3,324) Total expenses 110,860 91,735 202,596 132,973 Operating income 7,526 17,144 24,669 38,836 Other income (expense): Interest income 334 8 342 8 Interest expense (11,206) (10,692) (21,898) (8,971) Equity in income of equity method 140 44 185 57 investees Realized and unrealized net gains 25,330 (13,005) 12,325 61,261 (losses) on commodity derivatives Other (2) 7 4 (36) Income (loss) before income taxes 22,122 (6,494) 15,627 91,155 Income tax expense (368) (211) (578) (824) Net income (loss) $21,754 $(6,705) $15,049 $90,331 Income (loss) per unit -- basic and diluted $0.38 $(0.12) $0.26 $1.89 Weighted average number of units used in computing net income (loss) per unit -- Basic 57,246 57,077 57,162 47,826 Diluted 57,349 57,077 57,195 47,826 LEGACY RESERVES LP CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (dollars in thousands) June 30, December 31, 2013 2012 ASSETS Current assets: Cash and cash equivalents $3,991 $3,509 Accounts receivable, net: Oil and natural gas 45,615 37,547 Joint interest owners 18,781 27,851 Other 411 551 Fair value of derivatives 8,518 15,158 Prepaid expenses and other current assets 5,081 3,294 Total current assets 82,397 87,910 Oil and natural gas properties, at cost: Proved oil and natural gas properties using the 2,192,538 2,078,961 successful efforts method of accounting Unproved properties 70,265 65,968 Accumulated depletion, depreciation, amortization (659,918) (573,003) and impairment 1,602,885 1,571,926 Other property and equipment, net of accumulated depreciation and amortization of $5,281 and $4,618, 3,442 2,646 respectively Operating rights, net of amortization of $3,778 and 3,239 3,486 $3,531, respectively Fair value of derivatives 31,579 15,834 Other assets, net of amortization of $8,964 and 19,068 7,804 $7,909, respectively Investments in equity method investees 4,180 393 Total assets $1,746,790 $1,689,999 LIABILITIES AND UNITHOLDERS' EQUITY Current liabilities: Accounts payable $4,161 $1,822 Accrued oil and natural gas liabilities 69,824 50,162 Fair value of derivatives 8,232 10,801 Asset retirement obligation 2,338 29,501 Other 9,321 11,437 Total current liabilities 93,876 103,723 Long-term debt 852,872 775,838 Asset retirement obligation 169,313 132,682 Fair value of derivatives 3,155 5,590 Other long-term liabilities 1,857 1,886 Total liabilities 1,121,073 1,019,719 Commitments and contingencies Unitholders' equity: Limited partners' equity - 57,274,363 and 57,038,942 units issued and outstanding at June 30, 2013 and 625,627 670,183 December 31, 2012, respectively General partner's equity (approximately 0.03%) 90 97 Total unitholders' equity 625,717 670,280 Total liabilities and unitholders' equity $1,746,790 $1,689,999 LEGACY RESERVES LP SELECTED FINANCIAL AND OPERATING DATA Three Months Ended Six Months Ended June 30, March 31, June 30, 2013 2013 2013 2012 (In thousands, except per unit data) Revenues: Oil sales $97,852 $90,357 $188,209 $141,925 Natural gas liquids (NGL) sales 3,161 3,342 6,503 7,250 Natural gas sales 17,373 15,180 32,553 22,634 Total revenues $118,386 $108,879 $227,265 $171,809 Expenses: Oil and natural gas production $34,265 $32,385 $66,650 $46,859 Ad valorem taxes 2,919 2,966 5,885 4,435 Total oil and natural gas production including ad valorem $37,184 $35,351 $72,535 $51,294 taxes Production and other taxes $6,771 $6,927 $13,698 $9,904 General and administrative $5,720 $5,295 $11,017 $10,079 excluding LTIP LTIP expense 1,344 986 2,329 1,532 Total general and administrative $7,064 $6,281 $13,346 $11,611 Depletion, depreciation, $39,113 $41,652 $80,765 $48,209 amortization and accretion Realized commodity derivative settlements: Realized gains (losses) on oil $(1,934) $229 $(1,705) $(13,057) derivatives Realized gains on natural gas $584 $2,406 $2,990 $8,967 derivatives Production: Oil (MBbls) 1,089 1,114 2,203 1,578 Natural gas liquids (MGal) 3,320 2,893 6,213 7,116 Natural gas (MMcf) 3,649 3,546 7,194 5,203 Total (MBoe) 1,776 1,774 3,550 2,615 Average daily production (Boe/d) 19,516 19,711 19,613 14,368 Average sales price per unit (excluding commodity derivatives): Oil price (per Bbl) $89.85 $81.11 $85.43 $89.94 Natural gas liquids price (per $0.95 $1.16 $1.05 $1.02 Gal) Natural gas price (per Mcf) $4.76 $4.28 $4.53 $4.35 Combined (per Boe) $66.66 $61.37 $64.02 $65.70 Average sales price per unit (including realized commodity derivative gains/losses): Oil price (per Bbl) $88.08 $81.32 $84.66 $81.67 Natural gas liquids price (per $0.95 $1.16 $1.05 $1.02 Gal) Natural gas price (per Mcf) $4.92 $4.96 $4.94 $6.07 Combined (per Boe) $65.90 $62.86 $64.38 $64.14 NYMEX oil index prices per Bbl: Beginning of Period $97.23 $91.82 $91.82 $98.83 End of Period $96.56 $97.23 $96.56 $84.96 NYMEX gas index prices per Mcf: Beginning of Period $4.02 $3.35 $3.35 $2.99 End of Period $3.57 $4.02 $3.57 $2.82 Average unit costs per Boe: Oil and natural gas production $19.29 $18.26 $18.77 $17.92 Ad valorem taxes $1.64 $1.67 $1.66 $1.70 Production and other taxes $3.81 $3.90 $3.86 $3.79 General and administrative $3.22 $2.98 $3.10 $3.85 excluding LTIP Total general and administrative $3.98 $3.54 $3.76 $4.44 Depletion, depreciation, $22.02 $23.48 $22.75 $18.44 amortization and accretion 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 equity method investees; *Unit-based compensation expense (benefit) related to LTIP unit awards accounted for under the equity or liability methods; *Minimum payments earned in excess of overriding royalty interest; *EBITDA applicable to equity method investee; 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 *Maintenance capital expenditures. The following table presents a reconciliation of our consolidated net income (loss) to Adjusted EBITDA and Distributable Cash Flow: Three MonthsEnded Six Months Ended June 30, March 31, June 30, 2013 2013 2013 2012 (dollars in thousands) Net income (loss) $21,754 $(6,705) $15,049 $90,331 Plus: Interest expense 11,206 10,692 21,898 8,971 Income tax expense 368 211 578 824 Depletion, depreciation, amortization and 39,113 41,652 80,765 48,209 accretion Impairment of long-lived 20,774 1,743 22,517 15,279 assets Gain on sale of assets (46) (219) (265) (3,324) Equity in income of (140) (44) (185) (57) equity method investees Unit-based compensation 1,344 986 2,329 1,532 expense Minimum payments earned in excess of overriding 10 400 410 -- royalty interest ^(1) EBITDA applicable to equity method investee 226 -- 226 -- ^(2) Unrealized (gains) losses on oil and (26,680) 15,640 (11,040) (65,351) natural gas derivatives Adjusted EBITDA $67,929 $64,356 $132,282 $96,414 Less: Cash interest expense 11,866 11,578 23,444 9,113 Cash settlements of LTIP 287 858 1,145 2,381 unit awards Maintenance capital 17,000 17,000 34,000 expenditures ^(3) Total development 28,892 capital expenditures Distributable Cash Flow $38,776 $34,920 $73,693 $56,028 (1) Minimum payments earned in excess of overriding royalties earned under a contractual agreement expiring December 31, 2019. The remaining amount of the minimum payments are recognized in net income. (2) EBITDA applicable to equity method investee is defined as the equity method investee's net income plus interest expense and depreciation. (3) Beginning in the first quarter of 2013, Legacy began deducting only maintenance capital expenditures instead of total development capital expenditures in the computation and presentation of Distributable Cash Flow, which results in the measure of Distributable Cash Flow not being comparable to those during any prior periods. CONTACT: Legacy Reserves LP Dan Westcott Executive Vice President and Chief Financial Officer (432) 689-5200 company logo
Legacy Reserves LP Announces Second Quarter 2013 Results
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