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Legacy Reserves LP Announces Third Quarter 2012 Results

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MIDLAND, Texas, Oct. 30, 2012 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced its third quarter results for 2012.

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

Three Months Ended Nine Months Ended
September 30,
September 30,
2012
June 30,
2012
2012 2011
(dollars in millions)
Production (Boe/d) 14,772 14,297 14,504 12,842
Revenue $84.2 $79.2 $256.0 $250.0
Commodity derivative cash settlements received (paid) $6.1 ($2.0) $2.0 ($3.8)
Expenses $75.2 $75.3 $208.2 $170.4
Operating income $9.0 $3.9 $47.8 $79.6
Unrealized gains (losses) on commodity derivatives ($33.3) $86.4 $32.1 $71.5
Net income (loss) ($23.6) $82.9 $66.8 $130.6
Adjusted EBITDA (*) $49.3 $40.7 $145.2 $148.3
Development capital expenditures $19.6 $16.7 $48.5 $52.1
Distributable Cash Flow (*) $23.4 $19.1 $78.9 $79.1
* 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 third quarter of 2012 compared to the second quarter of 2012 include the following:

  • Production increased 3% to 14,772 Boe per day in the third quarter from 14,297 Boe per day in the second quarter. Our third quarter production increased primarily due to a full quarter impact of approximately $105.2 million of acquisitions of producing properties that closed during the second quarter as well as another $7.9 million of acquisitions of producing properties that closed during the third quarter. Our third quarter production was negatively impacted by high pressures in natural gas gathering lines in the Permian Basin primarily due to extensive development in the area.
  • Average realized prices, excluding commodity derivatives settlements, were $61.95 per Boe in the third quarter, up 2% from $60.85 per Boe in the second quarter. Average realized oil prices increased slightly to $83.54 per Bbl in the third quarter from $83.27 per Bbl in the second quarter. While average West Texas Intermediate ("WTI") crude oil prices declined slightly ($1.07 per Bbl) during the third quarter compared to the second quarter, oil differentials decreased by a larger amount ($1.33 per Bbl) during the third quarter, resulting in a slightly higher realized price. These decreased differentials were primarily driven by a Midland-to-Cushing/WTI differential that averaged approximately $1.75 per Bbl in the third quarter compared to approximately $4.91 per Bbl in the second quarter. This decreased Midland-to-Cushing differential was partially offset by a full quarter impact of our acquisitions in the Rockies, which typically have higher crude oil differentials than our properties in the Permian Basin. In addition, average realized natural gas prices increased 6% to $4.10 per Mcf in the third quarter from $3.87 per Mcf in the second quarter, and average realized NGL prices decreased 6% to $0.91 per gallon in the third quarter from $0.97 per gallon in the second 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 $84.2 million in the third quarter, an increase of 6% from $79.2 million in the second quarter due to higher production and slightly higher realized commodity prices per Boe.
  • Production expenses, excluding taxes, increased 18% to $28.2 million in the third quarter from $23.9 million in the second quarter due to production expenses associated with recent acquisitions as well as higher remedial workover and other non-recurring expenses. Workover expenses during the third quarter, which were primarily casing repairs and repairs or replacements of submersible pumps, totaled approximately $3.5 million, or approximately $2.0 million higher than our total in the second quarter. Production expenses per Boe increased 13% to $20.76 per Boe in the third quarter from $18.35 per Boe in the second quarter.
  • Legacy's general and administrative expenses were $7.0 million or $5.15 per Boe during the third quarter compared to $5.2 million or $3.97 per Boe during the second quarter. This increase was due to higher unit-based compensation expense, which increased to $2.1 million during the third quarter from a benefit of approximately $24,000 during the second quarter. This increase in unit-based compensation expense was due to an increase in our LTIP liability and recording of a corresponding compensation expense primarily due to our unit price increasing $3.82 between the end of the second quarter and the end of the third quarter. In contrast, the recording of a $24,000 benefit during the second quarter was primarily due to our unit price decreasing by $3.91 between the end of the first quarter and the end of the second quarter.
  • Cash settlements received on our commodity derivatives during the third quarter were $6.1 million compared to $2.0 million paid during the second 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 the corresponding volumes are hedged. After WTI crude oil prices averaged approximately $82 per barrel in June 2012, we received settlements of $2.0 million on our June oil hedges in early July, which impacted our third quarter results. In contrast, after WTI crude oil prices averaged approximately $94.50 per barrel in September, we paid settlements of $0.7 million on our September oil hedges in early October, which will impact our fourth quarter results. This lag effect on crude oil hedges during a period of increasing oil prices caused our cash settlements received on our oil hedges to be approximately $2.7 million higher during the third quarter. In contrast, this lag effect during a period of decreasing prices caused our cash settlements paid on our oil hedges to be approximately $5.2 million higher during the second quarter. We also reported unrealized losses of $33.3 million on our commodity derivatives portfolio during the third quarter due to the impact of increasing NYMEX oil and natural gas futures prices from the end of the second quarter until the end of the third quarter. As a result of these unrealized losses, our commodity derivatives net asset of $56.9 million at June 30, 2012 was reduced to a net asset of $23.6 million at September 30, 2012. In comparison, we reported unrealized gains of $86.4 million on our commodity derivatives portfolio during the second quarter due to decreasing oil prices partially offset by increasing natural gas prices.
  • Adjusted EBITDA increased 21% to $49.3 million during the third quarter from $40.7 million during the second quarter primarily due to higher production in the third quarter, slightly higher realized commodity prices (due mostly to improved oil differentials) in the third quarter, a $2.7 million positive oil hedge lag effect in the third quarter and a $5.2 million negative oil hedge lag effect in the second quarter. Adjusted EBITDA for the third quarter was further impacted by remedial workover and other non-recurring expenses that resulted in higher production expenses, excluding 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 by 17% to $19.6 million in the third quarter from $16.7 million in the second quarter, making it the second highest quarter for development capital expenditures in Legacy's history. This increase was driven by a full quarter of our Wolfberry drilling program as well as partial drilling costs from an operated horizontal Bone Spring well from which we should realize production during the latter half of the fourth quarter.
  • Distributable cash flow increased to $23.4 million in the third quarter compared to $19.1 million in the second quarter. This increase was due to significantly higher Adjusted EBITDA that was partially offset by higher development capital expenditures, higher cash settlements paid to non-executive employees on our LTIP unit awards, and slightly higher cash interest expense in the third quarter compared to the second quarter.
  • We incurred a net loss of $23.6 million, or $0.49 per unit, in the third quarter, which included unrealized losses of $33.3 million on our commodity derivatives and a $7.3 million impairment charge on our oil and natural gas properties. We reported net income of $82.9 million, or $1.73 per unit, in the second quarter, which included unrealized gains of $86.4 million on our commodity derivatives and a $14.0 million impairment charge on our oil and natural gas properties.

Cary Brown, Chairman, President and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, commented: "Legacy posted strong financial and operational results in the third quarter with record production as we benefitted from our strong acquisitions efforts and our ongoing capital program. Although our production expenses were higher than anticipated due to several remedial workovers and other non-recurring expenses, our internal line item analysis indicates little to no cost inflation in our recurring production expenses, and we kept our other cash expenses in line. These factors along with improved oil differentials and positive hedging settlements of $6.1 million allowed us to generate Adjusted EBITDA of $49.3 million, an increase of 21% over the second quarter. On the development front, we invested $19.6 million in capital projects and remain encouraged by our oil-weighted drilling efforts on our operated Wolfberry and Bone Spring locations and non-operated projects. We also increased our 2012 development capital expenditures budget from $62 million to $66 million, and believe this incremental $4 million will generate organic growth supporting future cash distributions to our unitholders. For the quarter, we reported approximately $23.4 million or $0.49 per unit of distributable cash flow, covering our $0.565 quarterly distribution per unit by 0.87 times. Our capital expenditures on high-quality development opportunities in the third quarter amounted to roughly 40% of our Adjusted EBITDA, which was significantly higher than our historical investment rate and thus negatively impacted our distributable cash flow and coverage ratio for the quarter, as we (unlike our peers) deduct all of our development capital when calculating our distributable cash flow. Assuming we had invested 30% of our Adjusted EBITDA in development capital expenditures, our coverage ratio would have been approximately 1.04 times."

"We are encouraged about our pipeline of potential acquisitions in the Permian Basin and other core areas, which is as strong as it has been in the Company's history. Based on our strong financial and operational results, our pipeline of potential acquisitions and our positive outlook into the fourth quarter of 2012 and calendar year 2013, we increased our quarterly distribution for the eighth consecutive quarter to $0.565 per unit which will be paid on November 14, 2012. On a year-over-year basis, we have increased our quarterly distribution by 3.7%."

Dan Westcott, Executive Vice President and Chief Financial Officer, commented, "We are very pleased with our third quarter results, as we increased our production to record levels, produced strong financial results, continued to invest in attractive oil drilling projects, and closed additional accretive acquisitions. On October 1, our 14-member bank group redetermined our borrowing base at $600 million. As of October 30, we have a debt balance of $462 million, leaving us with approximately $138 million of current availability under our credit agreement. With support from our banks and strong public equity and debt capital markets, we are confident in our ability to finance future potential acquisitions."

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 October 30, 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 in the following tables:

Crude Oil (WTI):

Calendar Year Volumes (Bbls) Average
Price per Bbl
Price
Range per Bbl
October-December 2012 583,570 $89.64 $67.72 - $109.20
2013 1,571,443 $90.34 $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 WTI 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 October 30, 2012:

Calendar Year Volumes (Bbls) Average Short
Put Price
Average Long
Put Price
Average Short
Call Price
October-December 2012 110,400 $68.13 $95.00 $113.54
2013 795,670 $66.24 $91.92 $112.25
2014 1,226,130 $65.64 $90.86 $113.29
2015 1,126,000 $65.43 $90.43 $114.76
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:

Calendar Year Volumes (Bbls) Floor
Price
Ceiling
Price
October-December 2012 16,400 $ 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
October-December 2012 1,644,610 $5.11 $2.46 - $8.70
2013 5,790,654 $4.76 $3.23 - $6.89
2014 4,251,254 $4.65 $3.61 - $6.47
2015 1,339,300 $5.65 $5.14 - $5.82
2016 219,200 $5.30 $5.30

We have entered into a costless collar for WAHA natural gas with the following attributes:

Calendar Year Volumes (MMBtu) Floor
Price
Ceiling
Price
October-December 2012 90,000 $ 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 September 30, 2012 Form 10-Q.

Conference Call

As announced on October 25, 2012, Legacy will host an investor conference call to discuss Legacy's results on Wednesday, October 31, 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 Sunday, November 4, 2012, by dialing (855) 859-2056 or (404) 537-3406 and entering replay code 47056291. Those wishing to listen to the live or archived webcast 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 LP
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, June 30, September 30,
2012 2012 2012 2011
(In thousands, except per unit data)
Revenues:
Oil sales $ 70,173 $ 65,787 $ 212,097 $ 196,220
Natural gas liquids (NGL) sales 3,492 3,524 10,742 13,896
Natural gas sales 10,531 9,851 33,166 39,858
Total revenues 84,196 79,162 256,005 249,974
Expenses:
Oil and natural gas production 30,728 26,406 82,023 71,304
Production and other taxes 5,137 4,687 15,040 15,101
General and administrative 6,993 5,161 18,604 14,630
Depletion, depreciation, amortization and accretion 24,833 25,370 73,042 64,152
Impairment of long-lived assets 7,277 13,978 22,556 5,869
(Gain) loss on disposal of assets 260 (313) (3,064) (680)
Total expenses 75,228 75,289 208,201 170,376
Operating income 8,968 3,873 47,804 79,598
Other income (expense):
Interest income 3 4 11 12
Interest expense (5,285) (4,636) (14,256) (15,633)
Equity in income of partnership 30 32 87 107
Realized and unrealized net gains (losses) on commodity derivatives (27,177) 84,350 34,084 67,753
Other (51) (68) (87) (55)
Income (loss) before income taxes (23,512) 83,555 67,643 131,782
Income tax expense (54) (613) (878) (1,198)
Net income (loss) $ (23,566) $ 82,942 $ 66,765 $ 130,584
Income (loss) per unit -- basic and diluted $ (0.49) $ 1.73 $ 1.40 $ 3.00
Weighted average number of units used in computing net income (loss) per unit --
Basic 47,869 47,850 47,840 43,560
Diluted 47,869 47,850 47,840 43,572
LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEET (UNAUDITED)
(dollars in thousands)
September 30,
2012
ASSETS
Current assets:
Cash and cash equivalents $ 4,366
Accounts receivable, net:
Oil and natural gas 35,161
Joint interest owners 13,322
Other 394
Fair value of derivatives 9,633
Prepaid expenses and other current assets 4,144
Total current assets 67,020
Oil and natural gas properties, at cost:
Proved oil and natural gas properties using the successful efforts method of accounting 1,544,197
Unproved properties 28,746
Accumulated depletion, depreciation, amortization and impairment (531,184)
1,041,759
Other property and equipment, net of accumulated depreciation and amortization of $4,306 2,726
Deposits on pending acquisitions 930
Operating rights, net of amortization of $3,407 3,610
Fair value of derivatives 19,950
Other assets, net of amortization of $7,480 5,930
Investment in equity method investee 369
Total assets $ 1,142,294
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 6,224
Accrued oil and natural gas liabilities 52,262
Fair value of derivatives 9,024
Asset retirement obligation 22,158
Other 8,596
Total current liabilities 98,264
Long-term debt 452,000
Asset retirement obligation 105,490
Fair value of derivatives 7,932
Other long-term liabilities 1,628
Total liabilities 665,314
Commitments and contingencies
Unitholders' equity:
Limited partners' equity - 47,868,942 units issued and outstanding 476,883
General partner's equity (approximately 0.04%) 97
Total unitholders' equity 476,980
Total liabilities and unitholders' equity $ 1,142,294
LEGACY RESERVES LP
SELECTED FINANCIAL AND OPERATING DATA
Three Months Ended Nine Months Ended
September 30, June 30, September 30,
2012 2012 2012 2011
(In thousands, except per unit data)
Revenues:
Oil sales $ 70,173 $ 65,787 $ 212,097 $ 196,220
Natural gas liquids sales 3,492 3,524 10,742 13,896
Natural gas sales 10,531 9,851 33,166 39,858
Total revenues $ 84,196 $ 79,162 $ 256,005 $ 249,974
Expenses:
Oil and natural gas production $ 28,207 $ 23,877 $ 75,067 $ 64,572
Ad valorem taxes $ 2,521 $ 2,529 $ 6,956 $ 6,732
Total oil and natural gas production including ad valorem taxes $ 30,728 $ 26,406 $ 82,023 $ 71,304
Production and other taxes $ 5,137 $ 4,687 $ 15,040 $ 15,101
General and administrative $ 6,993 $ 5,161 $ 18,604 $ 14,630
Depletion, depreciation, amortization and accretion $ 24,833 $ 25,370 $ 73,042 $ 64,152
Realized commodity derivative settlements:
Realized gains (losses) on oil derivatives $ 2,108 $ (6,855) $ (10,949) $ (11,849)
Realized gains on natural gas derivatives $ 4,000 $ 4,817 $ 12,967 $ 8,084
Production:
Oil (MBbls) 840 790 2,418 2,190
Natural gas liquids (MGal) 3,821 3,626 10,938 10,509
Natural gas (MMcf) 2,571 2,545 7,774 6,397
Total (MBoe) 1,359 1,301 3,974 3,506
Average daily production (Boe/d) 14,772 14,297 14,504 12,842
Average sales price per unit (excluding commodity derivatives):
Oil price (per Bbl) $ 83.54 $ 83.27 $ 87.72 $ 89.60
Natural gas liquids price (per Gal) $ 0.91 $ 0.97 $ 0.98 $ 1.32
Natural gas price (per Mcf) $ 4.10 $ 3.87 $ 4.27 $ 6.23
Combined (per Boe) $ 61.95 $ 60.85 $ 64.42 $ 71.30
Average sales price per unit (including realized commodity derivative gains/losses):
Oil price (per Bbl) $ 86.05 $ 74.60 $ 83.19 $ 84.19
Natural gas liquids price (per Gal) $ 0.91 $ 0.97 $ 0.98 $ 1.32
Natural gas price (per Mcf) $ 5.65 $ 5.76 $ 5.93 $ 7.49
Combined (per Boe) $ 66.45 $ 59.28 $ 64.93 $ 70.23
NYMEX oil index prices per Bbl:
Beginning of Period $ 84.96 $ 103.02 $ 98.83 $ 91.38
End of Period $ 92.19 $ 84.96 $ 92.19 $ 79.20
NYMEX natural gas index prices per Mcf:
Beginning of Period $ 2.82 $ 2.13 $ 2.99 $ 4.41
End of Period $ 3.32 $ 2.82 $ 3.32 $ 3.67
Average unit costs per Boe:
Oil and natural gas production $ 20.76 $ 18.35 $ 18.89 $ 18.42
Ad valorem taxes $ 1.86 $ 1.94 $ 1.75 $ 1.92
Production and other taxes $ 3.78 $ 3.60 $ 3.78 $ 4.31
General and administrative $ 5.15 $ 3.97 $ 4.68 $ 4.17
Depletion, depreciation, amortization and accretion $ 18.27 $ 19.50 $ 18.38 $ 18.30

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 Nine Months Ended
September 30, June 30, September 30,
2012 2012 2012 2011
(dollars in thousands)
Net income (loss) $ (23,566) $ 82,942 $ 66,765 $ 130,584
Plus:
Interest expense 5,285 4,636 14,256 15,633
Income tax expense 54 613 878 1,198
Depletion, depreciation, amortization and accretion 24,833 25,370 73,042 64,152
Impairment of long-lived assets 7,277 13,978 22,556 5,869
Gain on sale of assets (9) (349) (3,846) --
Equity in income of partnership (30) (32) (87) (107)
Unit-based compensation expense (benefit) 2,138 (24) 3,670 2,446
Unrealized (gains) losses on oil and natural gas derivatives 33,285 (86,388) (32,066) (71,518)
Adjusted EBITDA $ 49,267 $ 40,746 $ 145,168 $ 148,257
Less:
Cash interest expense 5,283 4,859 14,396 14,182
Cash settlements of LTIP unit awards 990 112 3,371 2,855
Development capital expenditures 19,565 16,693 48,457 52,127
Distributable Cash Flow $ 23,429 $ 19,082 $ 78,944 $ 79,093
CONTACT: Legacy Reserves LP Dan Westcott Executive Vice President and Chief Financial Officer 432-689-5200

Source:Legacy Reserves LP