Legacy Reserves LP Announces Third Quarter 2015 Results

MIDLAND, Texas, Nov. 4, 2015 (GLOBE NEWSWIRE) — Legacy Reserves LP (“Legacy”) (NASDAQ:LGCY) today announced third quarter results for 2015.

Q3 highlights include:

  • Record production of 41,152 Boe/d
  • Lease operating expense (excluding ad valorem taxes) of $46.0 million, a $0.5 million (1.1%) improvement relative to Q2 2015 and a $10.9 million (20.4%) improvement relative to Q4 2014 when excluding the impact of recent acquisitions
  • Adjusted EBITDA of $55.3 million on a net loss of $90.1 million
  • Distributable Cash Flow of $24.1 million, covering our new $0.15 per unit quarterly distribution by 2.31 times

Paul T. Horne, President and Chief Executive Officer of Legacy commented, “Despite the commodity price headwind, the third quarter was a very productive quarter for Legacy. During the quarter we closed on approximately $476 million of acquisitions of East Texas properties, and have onboarded over 60 people to cover these assets. We are currently working on improving field processes and believe we have several accretive projects available to us in this area. Additionally, we are currently running two drilling rigs under our Development Agreement with TPG Special Situations Partners and are pleased with our early results. We continue to focus on the areas of our business that we can control and are glad to see our production costs decline further in the third quarter. Our team’s ability to drive down costs while holding production flat is absolutely spectacular.”

Dan Westcott, Executive Vice President and Chief Financial Officer of Legacy commented, “We had a good quarter, especially in light of the current industry environment. As we previously announced, we have reduced our annualized distribution to $0.60 per unit from $1.40 per unit. While we generated more than adequate coverage this quarter to pay our previous distribution amount, we made the difficult decision to prioritize our focus on our balance sheet. As we recently stated, we do not believe the current commodity prices are sustainable and believe it is in our unitholders’ best interest for us to turn greater attention to our balance sheet so that we can be best positioned when commodity prices recover. We currently have approximately $343 million of availability under our $950 million borrowing base which provides more than ample headroom to run our business. We expect to complete our fall redetermination in the coming weeks and expect only a modest reduction to our current borrowing base.”

LEGACY RESERVES LP
SELECTED FINANCIAL AND OPERATING DATA
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2015 2014 2015 2014
  (In thousands, except per unit data)
Revenues:        
Oil sales  $ 49,779  $ 105,640  $ 159,188  $ 316,426
Natural gas liquids sales 2,946 10,413 12,867 19,482
Natural gas sales 36,773 33,623 86,783 76,786
Total revenue  $ 89,498  $ 149,676  $ 258,838  $ 412,694
Expenses:        
Oil and natural gas production, excluding ad valorem taxes  $ 45,954  $ 51,835  $ 134,727  $ 133,528
Ad valorem taxes  $ 2,492  $ 3,656  $ 8,160  $ 10,306
Total oil and natural gas production  $ 48,446  $ 55,491  $ 142,887  $ 143,834
Production and other taxes  $ 4,834  $ 7,742  $ 13,038  $ 24,292
General and administrative, excluding acq. costs and LTIP  $ 8,040  $ 6,936  $ 22,345  $ 21,596
Acquisition costs  $ 6,502  $ 364  $ 8,176  $ 5,330
LTIP expense  $ 1,704  $ 1,025  $ 4,985  $ 3,855
Total general and administrative  $ 16,246  $ 8,325  $ 35,506  $ 30,781
Depletion, depreciation, amortization and accretion  $ 45,041  $ 48,016  $ 122,306  $ 120,250
Commodity derivative cash settlements:        
Oil derivative cash settlements received (paid)  $ 17,092 $ (6,239)  $ 76,656  $ (15,039)
Natural gas derivative cash settlements received  $ 9,696  $ 3,885  $ 27,658  $ 3,065
Production:        
Oil (MBbls) 1,149 1,221 3,520 3,532
Natural gas liquids (MGal) 10,084 10,697 31,336 19,578
Natural gas (MMcf) 14,383 8,867 33,689 16,970
Total (MBoe) 3,786 2,954 9,881 6,826
Average daily production (Boe/d) 41,152 32,109 36,194 25,004
Average sales price per unit (excluding derivative cash settlements):        
Oil price (per Bbl)  $ 43.32  $ 86.52  $ 45.22  $ 89.59
Natural gas liquids price (per Gal)  $ 0.29  $ 0.97  $ 0.41  $ 1.00
Natural gas price (per Mcf)  $ 2.56  $ 3.79  $ 2.58  $ 4.52
Combined (per Boe)  $ 23.64  $ 50.67  $ 26.20  $ 60.46
Average sales price per unit (including derivative cash settlements):        
Oil price (per Bbl)  $ 58.20  $ 81.41  $ 67.00  $ 85.33
Natural gas liquids price (per Gal)  $ 0.29  $ 0.97  $ 0.41  $ 1.00
Natural gas price (per Mcf)  $ 3.23  $ 4.23  $ 3.40  $ 4.71
Combined (per Boe)  $ 30.71  $ 49.87  $ 36.75  $ 58.70
Average WTI oil spot price (per Bbl)  $ 46.41  $ 97.25  $ 51.00  $ 99.62
Average Henry Hub natural gas index price (per Mcf)  $ 2.73  $ 3.95  $ 2.76  $ 4.41
Average unit costs per Boe:        
Oil and natural gas production  $ 12.14  $ 17.55  $ 13.63  $ 19.56
Ad valorem taxes  $ 0.66  $ 1.24  $ 0.83  $ 1.51
Production and other taxes  $ 1.28  $ 2.62  $ 1.32  $ 3.56
General and administrative excluding acq. costs and LTIP  $ 2.12  $ 2.35  $ 2.26  $ 3.16
Total general and administrative  $ 4.29  $ 2.82  $ 3.59  $ 4.51
Depletion, depreciation, amortization and accretion  $ 11.90  $ 16.25  $ 12.38  $ 17.62

Financial and Operating Results – Three-Month Period Ended September 30, 2015 Compared to Three-Month Period Ended September 30, 2014

  • Production increased 28% to 41,152 Boe/d from 32,109 Boe/d primarily due to our 2015 acquisitions including our East Texas acquisitions from WGR Operating LP and Anadarko E&P Onshore LLC (“Anadarko Acquisitions”).
  • Average realized price, excluding net cash settlements from commodity derivatives, decreased 53% to $23.64 per Boe in 2015 from $50.67 per Boe in 2014 driven by the significant decline in commodity prices as well as the increase of NGL and natural gas production as a percentage of total production. Average realized oil price decreased 50% to $43.32 in 2015 from $86.52 in 2014 driven by a decrease in the average West Texas Intermediate (“WTI”) crude oil price of $50.84 per Bbl partially offset by a decrease in realized regional differentials. Average realized natural gas price decreased 32% to $2.56 per Mcf in 2015 from $3.79 per Mcf in 2014. This decrease is a result of the decrease in the average Henry Hub natural gas index price of $1.22 per Mcf. Finally, our average realized NGL price decreased 70% to $0.29 per gallon in 2015 from $0.97 per gallon in 2014.
  • Production expenses, excluding ad valorem taxes, decreased 11% to $46.0 million in 2015 from $51.8 million in 2014. On an average cost per Boe basis, production expenses decreased 31% to $12.14 per Boe in 2015 from $17.55 per Boe in 2014, driven primarily by expense reduction efforts across the properties that we have owned prior to the Anadarko Acquisitions as well as the inclusion of lower cost natural gas properties acquired in the Anadarko Acquisitions.
  • General and administrative expenses, excluding unit-based Long-Term Incentive Plan (“LTIP”) compensation expense totaled $14.5 million in 2015 compared to $7.3 million in 2014. This increase was primarily due to a $6.1 million increase in acquisition costs between the periods as we incurred approximately $6.5 million of one-time acquisition-related expenses during the third quarter of 2015 associated with the Anadarko Acquisitions and an advisory fee related to the establishment of a Development Agreement with Jupiter JV, LP, which was formed by certain of TPG Special Situations Partners’ investment funds to participate in the funding, exploration, development and operation of certain of our currently undeveloped oil and gas properties.
  • Cash settlements received on our commodity derivatives during 2015 were $26.8 million compared to cash settlements paid of approximately $2.4 million in 2014.
  • Total development capital expenditures decreased to $7.9 million in 2015 from $33.5 million in 2014. The 2015 activity was comprised mainly of the drilling and completion of two non-operated horizontal wells and capital costs related to CO2 properties.
  • Non-cash impairment expense totaled $98.1 million due to the continued decline in oil and natural gas futures prices.

Financial and Operating Results – Nine-Month Period Ended September 30, 2015 Compared to Nine-Month Period Ended September 30, 2014

  • Production increased 45% to 36,194 Boe/d from 25,004 Boe/d primarily due to acquisitions in 2015 including the Anadarko Acquisitions.
  • Average realized price, excluding net cash settlements from commodity derivatives, decreased 57% to $26.20 per Boe in 2015 from $60.46 per Boe in 2014 driven by the significant decline in commodity prices as well as the increase in NGL and natural gas production as a percentage of total production. Average realized oil price decreased 50% to $45.22 in 2015 from $89.59 in 2014 driven by a decrease in the average WTI crude oil price of $48.62 per Bbl partially offset by a decrease in realized regional differentials. Average realized natural gas price decreased 43% to $2.58 per Mcf in 2015 from $4.52 per Mcf in 2014. This decrease is a result of the decrease in the average Henry Hub natural gas index price of approximately $1.65 per Mcf as well as the inclusion of lower priced natural gas production from the WPX Acquisition. Finally, our average realized NGL price decreased 59% to $0.41 per gallon in 2015 from $1.00 per gallon in 2014. This decrease is due to the combination of lower commodity prices and the full-period inclusion of lower priced NGL production from the WPX Acquisition.
  • Despite additional expenses from our WPX Acquisition, Anadarko Acquisitions and other recent acquisitions of approximately $24.0 million, our production expenses, excluding ad valorem taxes, increased only 1% to $134.7 million in 2015 from $133.5 million in 2014. On an average cost per Boe basis, production expenses decreased 30% to $13.63 per Boe in 2015 from $19.56 per Boe in 2014. These significant savings were driven primarily by expense reduction efforts across our historical property set ($22.8 million) as well as the inclusion of lower cost natural gas properties acquired in the WPX Acquisition and the Anadarko Acquisitions.
  • Non-cash impairment expense totaled $307.5 million driven by the significant decline in natural gas futures prices during the first and third quarters of 2015.
  • General and administrative expenses, excluding unit-based LTIP compensation expense totaled $30.5 million in 2015 compared to $26.9 million in 2014. This increase was primarily due to a $2.9 million increase in acquisition costs between the periods as we incurred approximately $8.2 million of one-time acquisition-related expenses during 2015 associated with the Anadarko Acquisitions and the establishment of the Development Agreement.
  • Cash settlements received on our commodity derivatives during 2015 were $104.3 million compared to cash settlements paid of approximately $12.0 million in 2014.
  • Total development capital expenditures decreased to $29.7 million in 2015 from $91.4 million in 2014. The 2015 activity was comprised mainly of the drilling and completion of two horizontal Wolfcamp wells, completion costs on an operated horizontal Bone Springs well, drilling and completion costs on two non-operated horizontal wells and capital costs related to CO2 properties.

Commodity Derivative Contracts

We enter into oil and natural gas derivative contracts to help mitigate the risk of changing commodity prices. As of November 4, 2015, we had entered into derivative agreements to receive average NYMEX WTI crude oil prices and NYMEX Henry Hub, Waha, NWPL, NGPA, SoCal, San Juan and CIG-Rockies natural gas prices as summarized below. Additionally, we have sold two call options related to an existing WTI oil swap. These swap related options (“swaptions”) allow the counterparty on December 31, 2015 the option to increase the volumes under contract covering calendar year 2016 to either double or triple the volumes of the current swap, which has nominal volumes of 366,000 Bbls.

WTI Crude Oil Swaps:

Time Period Volumes (Bbls) Average Price per Bbl Price Range per Bbl
October-December 2015 100,961 $90.49 $88.50 $99.85
2016 594,600 $68.37 $56.15 $99.85
2017 182,500 $84.75 $84.75

WTI Crude Oil 3-Way Collars:

    Average Short Put Average Long Put Average Short Call
Time Period Volumes (Bbls) Price per Bbl Price per Bbl Price per Bbl
October-December 2015 336,720 $64.78 $89.78 $110.57
2016 621,300 $63.37 $88.37 $106.40
2017 72,400 $60.00 $85.00 $104.20

WTI Crude Oil Enhanced Swaps:

      Average Short Put Average Swap
Time Period Volumes (Bbls) Price per Bbl Price per Bbl
October-December 2015 253,000 $77.73 $93.98
         
    Average Long Put Average Short Put Average Swap
Time Period Volumes (Bbls) Price per Bbl Price per Bbl Price per Bbl
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

Midland-to-Cushing WTI Crude Oil Differential Swaps:

Time Period Volumes (Bbls) Average Price per Bbl Price Range per Bbl
October-December 2015 828,000  $ (1.78)  $ (1.75)  –   $ (1.90)
2016 2,928,000  $ (1.60)  $ (1.50)  –   $ (1.75)
2017 2,190,000  $ (0.30)  $ (0.05)  –   $ (0.75)

Natural Gas Swaps (Henry Hub and Waha):

    Average      
Time Period Volumes (MMBtu) Price per MMBtu Price Range per MMBtu
October-December 2015 7,348,600 $3.96 $3.11 $5.82
2016 29,019,200 $3.40 $3.29 $5.30
2017 27,600,000 $3.36 $3.29 $3.39
2018 27,600,000 $3.36 $3.29 $3.39
2019 25,800,000 $3.36 $3.29 $3.39

Natural Gas 3-Way Collars (Henry Hub):

  Volumes Average Short Put Average Long Put Average Short Call
Time Period  (MMBtu) Price per MMBtu Price per MMBtu Price per MMBtu
October-December 2015 2,010,000 $3.66 $4.21 $5.01
2016 5,580,000 $3.75 $4.25 $5.08
2017 5,040,000 $3.75 $4.25 $5.53

Natural Gas Basis Swaps (NWPL, NGPA, SoCal, San Juan and Waha)

  October-December 2015 2016
    Average   Average
  Volumes (MMBtu) Price per MMBtu Volumes (MMBtu) Price per MMBtu
NWPL 3,000,000  $ (0.13) 14,977,818  $ (0.19)
NGPL 120,000  $ (0.15) $—
SoCal 60,000 $0.19 $—
San Juan 120,000  $ (0.12) 2,499,780  $ (0.16)
WAHA 1,500,000  $ (0.10) $—

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.

Quarterly Report on Form 10-Q

Financial results contained herein are preliminary and subject to the final, unaudited financial statements and related footnotes included in Legacy’s Form 10-Q which will be filed on or about November 6, 2015.

Conference Call

As announced on October 26, 2015, Legacy will host an investor conference call to discuss Legacy’s results on Thursday, November 5, 2015 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 Thursday, November 12, 2015, by dialing 855-859-2056 or 404-537-3406 and entering replay code 62019645. 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, East Texas, Rocky Mountain and Mid-Continent 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 Nine Months Ended
  September 30, September 30,
  2015 2014 2015 2014
  (In thousands, except per unit data)
Revenues:        
Oil sales  $ 49,779  $ 105,640  $ 159,188  $ 316,426
Natural gas liquids (NGL) sales 2,946 10,413 12,867 19,482
Natural gas sales 36,773 33,623 86,783 76,786
Total revenues 89,498 149,676 258,838 412,694
         
Expenses:        
Oil and natural gas production 48,446 55,491 142,886 143,834
Production and other taxes 4,834 7,742 13,038 24,292
General and administrative 16,246 8,325 35,506 30,781
Depletion, depreciation, amortization and accretion 45,041 48,016 122,306 120,250
Impairment of long-lived assets 98,054 4,785 307,455 8,583
(Gain) loss on disposal of assets 560 (1,683) 1,567 (3,235)
Total expenses 213,181 122,676 622,758 324,505
         
Operating income (loss) (123,683) 27,000 (363,920) 88,189
         
Other income (expense):        
Interest income (expense) (55) 223 326 662
Interest expense (23,351) (19,083) (58,903) (49,247)
Equity in income (loss) of equity method investees (6) 126 97 309
Net gains on commodity derivatives 57,000 55,994 63,982 8,675
Other 19 (166) 723 137
Incomes (loss) before income taxes (90,076) 64,094 (357,695) 48,725
Income tax (expense) benefit (1) (278) 290 (870)
Net income (loss) $ (90,077) $ 63,816 $ (357,405) $ 47,855
Distributions to Preferred unitholders (4,750) (4,750) (14,250) (6,944)
Net income (loss) attributable to unitholders $ (94,827) $ 59,066 $ (371,655) $ 40,911
         
Income (loss) per unit – basic $ (1.38)  $ 1.03 $ (5.39)  $ 0.71
Income (loss) per unit – diluted $ (1.38)  $ 1.02 $ (5.39)  $ 0.71
Weighted average number of units used in computing net loss per unit —        
Basic 68,945 57,406 68,921 57,363
Diluted 68,945 57,643 68,921 57,523
         
         
LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
ASSETS
  September 30, December 31,
  2015 2014
  (In thousands)
Current assets:    
Cash  $ 1,627  $ 725
Accounts receivable, net:    
Oil and natural gas 48,381 49,390
Joint interest owners 27,795 16,235
Other 130 237
Fair value of derivatives 64,500 120,305
Prepaid expenses and other current assets 5,487 5,362
Total current assets 147,920 192,254
Oil and natural gas properties using the successful efforts method, at cost:    
Proved properties 3,502,151 2,946,820
Unproved properties 48,773 47,613
Accumulated depletion, depreciation, amortization and impairment (1,766,523) (1,354,459)
  1,784,401 1,639,974
Other property and equipment, net of accumulated depreciation and amortization of $8,489 and $7,446, respectively 4,300 3,767
Operating rights, net of amortization of $4,842 and $4,509, respectively 2,175 2,508
Fair value of derivatives 48,269 32,794
Other assets, net of amortization of $14,774 and $12,551, respectively 23,623 24,255
Investments in equity method investees 617 3,054
Total assets  $ 2,011,305  $ 1,898,606
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:    
Accounts payable  $ 3,317  $ 2,787
Accrued oil and natural gas liabilities 59,244 78,615
Fair value of derivatives 3,266 2,080
Asset retirement obligation 3,028 3,028
Other 25,442 11,066
Total current liabilities 94,297 97,576
Long-term debt 1,451,700 938,876
Asset retirement obligation 285,306 223,497
Fair value of derivatives 807
Other long-term liabilities 1,229 1,452
Total liabilities 1,833,339 1,261,401
Commitments and contingencies    
Partners’ equity    
Series A Preferred equity – 2,300,000 units issued and outstanding at September 30, 2015 and December 31, 2014 55,192 55,192
Series B Preferred equity – 7,200,000 units issued and outstanding at September 30, 2015 and December 31, 2014 174,261 174,261
Incentive distribution equity – 100,000 units issued and outstanding at September 30, 2015 and December 31, 2014 30,814 30,814
Limited partners’ equity (deficit) – 68,949,561 and 68,910,784 units issued and outstanding at September 30, 2015 and December 31, 2014, respectively (82,259) 376,885
General partner’s equity (deficit) (approximately 0.03%) (42) 53
Total partners’ equity 177,966 637,205
Total liabilities and partners’ equity  $ 2,011,305  $ 1,898,606
     

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 concerning the performance of our business and are used by investors and financial analysts to analyze and compare our current operating and financial performance relative to past performance and such performances relative to that of other publicly traded partnerships in the industry. Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other publicly traded limited partnerships or limited liability companies because all companies may not calculate such measures in the same manner.

Distributable Cash Flow is one of the factors used by the board of directors of our general partner (the “Board”) to help determine the amount of Available Cash as defined in our partnership agreement, that is to be distributed to our unitholders for such period. Under our partnership agreement, Available Cash is defined generally to mean, cash on hand at the end of each quarter, plus working capital borrowings made after the end of the quarter, less cash reserves determined by our general partner. The Board determines whether to increase, maintain or decrease the current level of distributions in accordance with the provisions of our partnership agreement based on a variety of factors, including without limitation, Distributable Cash Flow, cash reserves established in prior periods, reserves established for future periods, borrowing capacity for working capital, temporary, one-time or uncharacteristic historical results, and forecasts of future period results including the impact of pending acquisitions. Management and the Board consider the long-term view of expected results in determining the amount of its distributions. Certain factors impacting Adjusted EBITDA and Distributable Cash Flow may be viewed as temporary, one-time in nature, or being offset by reserves from past performance or near-term future performance. Financial results are also driven by various factors that do not typically occur evenly throughout the year that are difficult to predict, including rig availability, weather, well performance, the timing of drilling and completions and near-term commodity price changes. Consistent with practices common to publicly traded partnerships, the Board historically has not varied the distribution it declares based on such timing effects.

“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.

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, September 30,
  2015 2014 2015 2014
  (In thousands)
Net income (loss) $ (90,077)  $ 63,816 $ (357,405)  $ 47,855
Plus:        
Interest expense 23,351 19,083 58,903 49,247
Income tax expense (benefit) 1 278 (290) 870
Depletion, depreciation, amortization and accretion 45,041 48,016 122,306 120,250
Impairment of long-lived assets 98,054 4,785 307,455 8,583
(Gain) loss on disposal of assets 560 (1,683) 1,567 (3,235)
Equity in income (loss) of equity method investees 6 (126) (97) (309)
Unit-based compensation expense 1,704 1,025 4,985 3,855
Minimum payments received in excess of overriding royalty interest earned(1) 386 349 1,130 1,023
Equity in EBITDA of equity method investee(2) 150 169 649
Net gains on commodity derivatives (57,000) (55,994) (63,983) (8,675)
Net cash settlements received (paid) on commodity derivatives 26,788 (2,354) 104,314 (11,974)
Transaction expenses related to acquisitions 6,502 364 8,175 5,330
Adjusted EBITDA  $ 55,316  $ 77,709  $ 187,229  $ 213,469
         
Less:        
Cash interest expense 18,632 18,456 52,624 47,639
Cash settlements of LTIP unit awards 86 771
Estimated maintenance capital expenditures(3) NM* 18,200 NM* 54,200
Development capital expenditures(4) 7,881 NM* 29,663 NM*
Distributions on Series A and Series B preferred units 4,750 4,750 14,250 6,944
Distributable Cash Flow(3)  $ 24,053  $ 36,217  $ 90,692  $ 103,915
         
Distributions Attributable to Each Period(5)  $ 10,425  $ 42,191  $ 58,957  $ 111,621
         
Distribution Coverage Ratio(3)(6) 2.31x 0.86x 1.54x 0.93x

* Not meaningful due to the 2015 change in presentation

(1) Minimum payments received in excess of overriding royalties earned under a contractual agreement expiring December 31, 2019. The remaining amount of the minimum payments is recognized in net income.

(2) Equity in EBITDA of equity method investee is defined as the equity method investee’s net income or loss plus interest expense and depreciation. We divested our interest in this investee in May of 2015.

(3) Estimated maintenance capital expenditures are intended to represent the amount of capital required to fully offset declines in production, but do not target specific levels of proved reserves to be achieved. Estimated maintenance capital expenditures do not include the cost of new oil and natural gas reserve acquisitions, but rather the costs associated with converting proved developed non-producing, proved undeveloped and unproved reserves to proved developed producing reserves. These costs, which are incorporated in our annual capital budget as approved by the Board, include development drilling, recompletions, workovers and various other procedures to generate new or improve existing production on both operated and non-operated properties. Estimated maintenance capital expenditures are based on management’s judgment of various factors including the long-term (generally 5-10 years) decline rate of our current production and the projected productivity of our total development capital expenditures. Actual production decline rates and capital efficiency may materially differ from our projections and such estimated maintenance capital expenditures may not maintain our production. Further, because estimated maintenance capital expenditures are not intended to target specific levels of reserves, if we do not acquire new proved or unproved reserves, our total reserves will decrease over time and we would be unable to sustain production at current levels, which could adversely affect our ability to pay a distribution at the current level or at all.

(4) Represents total capital expenditures for the development of oil and natural gas properties as presented on an accrual basis. For 2015, we intend to fund our total oil and natural gas development program from net cash provided by operating activities. Previously, we intended to fund only a portion of our oil and natural gas development program from net cash provided by operating activities.

(5) Represents the aggregate cash distributions declared for the respective period and paid by Legacy to our unitholders within 45 days after the end of each quarter within such period.

(6) We refer to the ratio of Distributable Cash Flow over Distributions Attributable to Each Period (“Available Cash” available for distribution to our unitholders per our partnership agreement) as “Distribution Coverage Ratio.” If the Distribution Coverage Ratio is equal to or greater than 1.0x, then our cash flows are sufficient to cover our quarterly distributions to our unitholders with respect to such period. If the Distribution Coverage Ratio is less than 1.0x, then our cash flows with respect to such period were not sufficient to cover our quarterly distributions to our unitholders and we must borrow funds or use cash reserves established in prior periods to cover our quarterly distributions to our unitholders. The Board uses its discretion in determining if such shortfalls are temporary or if distributions should be adjusted downward.

CONTACT: Legacy Reserves LP
         Dan Westcott
         Executive Vice President and Chief Financial Officer
         432-689-5200