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Legacy Reserves LP Announces Second Quarter 2014 Results

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MIDLAND, Texas, July 30, 2014 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced second quarter results for 2014. Financial results contained herein are preliminary and subject to the final, unaudited financial statements included in Legacy's 10-Q to be filed on or about August 1, 2014.

Q2 and YTD 2014 highlights include:

  • Successful closing of our Strategic Alliance with WPX Energy along with closings of our two previously announced acquisitions in Chaves County, NM and Sheridan County, MT.
  • Record production of 23,286 and 21,392 Boe/d for the three and six month periods, respectively.
  • Record revenue of $137.1 million and $263.0 million for the three and six month periods, respectively.
  • Adjusted EBITDA of $70.0 million and $135.8 million for the three and six month periods, respectively.
  • Distributable Cash Flow of $33.4 million and $67.7 million for the three and six month periods, respectively.
  • A $57.5 million Series A Preferred Unit issuance at 8.0% (Nasdaq:LGCYP).
  • A $180 million Series B Preferred Unit issuance at 8.0% (Nasdaq:LGCYO).
  • A $300 million tack-on offering to our 6.625% Senior Notes due 2021.
  • A $0.015 per unit increase in our distribution to $0.61 per quarter, reflecting only a partial quarter contribution from our initial transaction with WPX Energy and representing a 10.5% annualized growth rate.

Cary D. Brown, Chairman, President and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, commented: "The second quarter is arguably our best quarter since going public. We closed $475.5 million of long-lived, accretive acquisitions while increasing distributions, balance sheet strength and liquidity under our revolver. We added a strategic partner and increased production to our highest levels to date. These developments allowed us to increase our quarterly distribution by $0.015, our largest quarterly increase since 2008. I am excited about the direction we are headed and the opportunities we are seeing. We continue to see value and great promise in our historical Permian footprint as new horizontal wells are being added daily around our acreage. I want to personally thank all our employees who have worked diligently to make this possible."

Dan Westcott, Executive Vice President and Chief Financial Officer, commented, "Q2 was indeed a great quarter. Our WPX Acquisition is a big step and one that we will be more excited to see fully flow through our financials next quarter. As we mentioned in May, we are hopeful that our newly-created IDR structure allows us to lengthen and broaden our prospects for future growth opportunities. We have recently raised over $530 million of long-term capital including over $230 million in 8.0% preferred equity and $300 million of additional senior notes. These instruments further strengthen our balance sheet with a conservative leverage profile allowing us to exit the quarter with $625 million of availability under our $950 million borrowing base. Our recent acquisitions are projected to provide significant asset-level growth and, when combined with our strong balance sheet, we look forward to seeing that increased value flow directly to our unitholders."

Financial and Operating Results – Second Quarter 2014 Compared to Second Quarter 2013

  • Production increased 19% to 23,286 Boe/d from 19,516 Boe/d primarily due to the WPX and other recent acquisitions, which closed during the quarter and thus contributed production for only a portion of the quarter.
  • Average realized price, excluding net cash settlements from commodity derivatives, decreased 3% to $64.71 per Boe in 2014 from $66.66 per Boe in 2013 due to the significant increase in natural gas and NGL production as such products are generally less valuable per Boe than oil. Average realized oil price increased 3% to $92.54 per Bbl in 2014 from $89.85 per Bbl in 2013. This increase of $2.69 per Bbl was attributable to an increase in the average West Texas Intermediate ("WTI") crude oil price of $9.30 per Bbl partially offset by higher realized regional differentials. Average realized natural gas price remained relatively flat at $4.77 per Mcf in 2014 compared to $4.76 per Mcf in 2013. While the average Henry Hub natural gas price index increased by $1.34 per Mcf in 2014, this increase was offset by relatively lower realized gas prices from the gas production associated with the WPX acquisition. Finally, our average realized NGL price decreased 3% to $0.92 per gallon in 2014 from $0.95 per gallon in 2013. The large majority of our separately-reported NGL production is from our Mid-Continent and Rockies regions.
  • Production expenses, excluding ad valorem taxes, increased 23% to $42.1 million in 2014 from $34.3 million in 2013. Production expenses increased primarily due to increased production resulting from additional properties acquired in Q2 of 2014 and the second half of 2013 as well as development activities and industry-wide cost increases.
  • Legacy's general and administrative expenses excluding unit-based/Long-Term Incentive Plan ("LTIP") compensation expense increased to $12.7 million in 2014 compared to $5.7 million in 2013. This increase was primarily attributable to $4.9 million of one-time acquisition related expenses as well as an increase in salary and benefit expenses related to the hiring of additional personnel to manage our larger asset base.
  • Cash settlements paid on our commodity derivatives were $6.0 million during 2014 compared to $1.4 million in 2013, a $4.6 million change between the periods.
  • Total development capital expenditures were $36.1 million in 2014 and were heavily weighted towards our Permian Wolfberry and Bone Spring drilling. Non-operated capital expenditures comprised 14% of our total capital expenditures in 2014 with activity primarily in the Permian and Mid-Continent.

Financial and Operating Results – Second Quarter Year to Date 2014 Compared to Second Quarter Year to Date 2013

  • Production increased 9% to 21,392 Boe/d from 19,613 Boe/d primarily due to the WPX and other recent acquisitions, which closed during the quarter and thus contributed production for only a portion of the quarter. These increases were partially offset by production declines in our Lower Abo assets as well as downtime related to inclement weather in the first quarter of 2014.
  • Average realized price, excluding net cash settlements from commodity derivatives, increased 6% to $67.93 per Boe in 2014 from $64.02 per Boe in 2013. Average realized oil price increased 7% to $91.25 per Bbl in 2014 from $85.43 per Bbl in 2013. This increase of $5.82 per Bbl was attributable to an increase in the average WTI crude oil price of $6.87 per Bbl partially offset by higher realized regional differentials. Average realized natural gas price increased 18% to $5.33 per Mcf in 2014 from $4.53 per Mcf in 2013. While the average Henry Hub natural gas price index increased by $1.09 per Mcf in 2014, this increase was partially offset by lower realized gas prices from the gas production associated with the WPX acquisition as compared to the prices realized by our Permian and Mid-Continent assets. Finally, our average realized NGL price decreased 2% to $1.02 per gallon in 2014 from $1.05 per gallon in 2013. The large majority of our separately reported NGL production is from our Mid-Continent and Rockies regions.
  • Production expenses, excluding ad valorem taxes, increased 23% to $81.7 million in 2014 from $66.7 million in 2013. Production expenses increased primarily due to increased production resulting from additional properties added in Q2 of 2014 and the second half of 2013, remedial workovers and other one-time well failure expenses. To a lesser extent, expenses associated with Legacy's development activities and industry-wide cost increases also contributed to the increase in production expenses.
  • Legacy's general and administrative expenses excluding LTIP compensation expense increased to $19.6 million in 2014 compared to $11.0 million in 2013. This increase was primarily attributable to $5.0 million of one-time acquisition related expenses as well as an increase in salary and benefit expenses related to the hiring of additional personnel to manage our larger asset base.
  • Cash settlements paid on our commodity derivatives were $9.6 million during 2014 compared to cash receipts of $1.3 million in 2013, a $10.9 million change between the periods.
  • Total development capital expenditures were $57.9 million in 2014 and were heavily weighted towards our Permian Wolfberry and Bone Spring drilling. Non-operated capital expenditures comprised 23% of our total capital expenditures in 2014 with activity primarily in the Permian and Mid-Continent.

Commodity Derivatives Contracts

We enter into oil and natural gas derivatives contracts to help mitigate the risk of changing commodity prices. As of July 30, 2014, we had entered into derivatives agreements to receive average NYMEX WTI crude oil prices and NYMEX Henry Hub, Waha, ANR-Oklahoma, NWPL, NGPA, SoCal, San Juan and CIG-Rockies natural gas prices as summarized below:

WTI Crude Oil Swaps:

Time Period Volumes (Bbls) Average
Price per Bbl
Price
Range per Bbl
July-December 2014 1,599,902 $93.58 $87.50 - $101.50
2015 1,056,301 $93.93 $88.50 - $100.20
2016 228,600 $87.94 $86.30 - $99.85
2017 182,500 $84.75 $84.75

WTI Crude Oil 3-Way Collars:

Time Period Volumes (Bbls) Average Short
Put Price per Bbl
Average Long
Put Price per Bbl
Average Short
Call Price per Bbl
July-December 2014 404,800 $71.59 $96.59 $110.71
2015 1,362,800 $65.08 $89.69 $111.84
2016 621,300 $63.37 $88.37 $106.40
2017 72,400 $60.00 $85.00 $104.20

WTI Crude Oil Enhanced Swaps:

Time Period Volumes (Bbls) Average Long
Put Price per Bbl
Average Short
Put Price per Bbl
Average Swap
Price per Bbl
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
Time Period Volumes (Bbls) Average Short
Put Price per Bbl
Average Swap
Price per Bbl
2015 503,000 $74.12 $93.09

Natural Gas Swaps (Henry Hub, WAHA, ANR-Oklahoma and CIG-Rockies):

Time Period Volumes (MMBtu) Average
Price per MMBtu
Price
Range per MMBtu
July-December 2014 12,625,262 $4.64 $3.61 - $6.47
2015 16,219,300 $4.45 $4.15 - $5.82
2016 1,419,200 $4.30 $4.12 - $5.30

Natural Gas 3-Way Collars (Henry Hub):

Time Period Volumes (MMBtu) Average Short Put
Price per MMBtu
Average Long Put
Price per MMBtu
Average Short Call
Price per MMBtu
July-December 2014 240,000 $4.00 $4.65 $5.03
2015 8,040,000 $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):

July-December 2014 2015
Volumes Average Price
per MMBtu
Volumes Average Price
per MMBtu
NWPL 5,700,000 ($0.08) 12,000,000 ($0.13)
NGPL 400,000 ($0.10) 480,000 ($0.15)
SoCal 400,000 $0.29 240,000 $0.19
San Juan 400,000 ($0.06) 480,000 ($0.12)
WAHA 1,150,000 ($0.06) 6,000,000 ($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

Our consolidated financial statements and related footnotes will be available in our Form 10-Q for the quarter ended June 30, 2014, which we plan to file on or about August 1, 2014.

Conference Call

As announced on July 22, 2014, Legacy will host an investor conference call to discuss Legacy's results on Thursday, July 31, 2014 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, August 7, 2014, by dialing 855-859-2056 or 404-537-3406 and entering replay code 74817855. 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
June 30,
Six Months Ended
June 30,
2014 2013 2014 2013
(In thousands, except per unit data)
Revenues:
Oil sales $ 108,731 $ 97,852 $ 210,786 $ 188,209
Natural gas liquids (NGL) sales 5,103 3,161 9,069 6,503
Natural gas sales 23,280 17,373 43,163 32,553
Total revenues 137,114 118,386 263,018 227,265
Expenses:
Oil and natural gas production 45,809 37,184 88,343 72,535
Production and other taxes 8,595 6,771 16,550 13,698
General and administrative 14,809 7,064 22,456 13,346
Depletion, depreciation, amortization and accretion 38,537 39,113 72,234 80,765
Impairment of long-lived assets 2,387 20,774 3,798 22,517
Gain on disposal of assets (3,853) (46) (1,552) (265)
Total expenses 106,284 110,860 201,829 202,596
Operating income 30,830 7,526 61,189 24,669
Other income (expense):
Interest income 216 334 439 342
Interest expense (16,225) (11,206) (30,164) (21,898)
Equity in income of equity method investees 191 140 183 185
Net gains (losses) on commodity derivatives (31,433) 25,330 (47,319) 12,325
Other 211 (2) 304 4
Income (loss) before income taxes (16,210) 22,122 (15,368) 15,627
Income tax expense (278) (368) (592) (578)
Net income (loss) $ (16,488) $ 21,754 $ (15,960) $ 15,049
Distributions to Preferred unitholders (2,194) -- (2,194) --
Net income (loss) attributable to unitholders $ (18,682) $ 21,754 $ (18,154) $ 15,049
Income (loss) per unit -
basic and diluted $ (0.33) $ 0.38 $ (0.32) $ 0.26
Weighted average number of units used in computing net income (loss) per unit -
Basic 57,372 57,246 57,341 57,162
Diluted 57,372 57,349 57,341 57,195
LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30,
2014
December 31,
2013
ASSETS (dollars in thousands)
Current assets:
Cash $ 10,139 $ 2,584
Accounts receivable, net:
Oil and natural gas 66,322 47,429
Joint interest owners 25,454 16,532
Other 721 626
Fair value of derivatives 823 3,801
Prepaid expenses and other current assets 6,076 3,727
Total current assets 109,535 74,699
Oil and natural gas properties using the successful efforts method, at cost:
Proved properties 2,819,660 2,265,788
Unproved properties 81,511 58,392
Accumulated depletion, depreciation, amortization and impairment (857,983) (788,751)
2,043,188 1,535,429
Other property and equipment, net of accumulated depreciation and amortization of $6,368 and $6,053, respectively 3,573 3,688
Deposits on pending acquisitions 5,800 --
Operating rights, net of amortization of $4,145 and $4,024, respectively 2,750 2,992
Fair value of derivatives 3,158 21,292
Other assets, net of amortization of $10,652 and $10,097, respectively 25,181 17,641
Investments in equity method investees 3,146 4,092
Total assets $ 2,196,331 $ 1,659,833
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Accounts payable $ 13,093 $ 6,016
Accrued oil and natural gas liabilities 83,596 63,161
Fair value of derivatives 24,008 10,060
Asset retirement obligation 2,610 2,610
Other 14,203 12,043
Total current liabilities 137,510 93,890
Long-term debt 1,153,687 878,693
Asset retirement obligation 219,188 173,176
Fair value of derivatives 3,331 2,119
Other long-term liabilities 1,635 1,559
Total liabilities 1,515,351 1,149,437
Total partners' equity 680,980 510,396
Total liabilities and partners' equity $ 2,196,331 $ 1,659,833
LEGACY RESERVES LP
SELECTED FINANCIAL AND OPERATING DATA
Three Months Ended
June 30,
Six Months Ended
June 30,
2014 2013 2014 2013
(In thousands, except per unit data)
Revenues:
Oil sales $ 108,731 $ 97,852 $ 210,786 $ 188,209
Natural gas liquids (NGL) sales 5,103 3,161 9,069 6,503
Natural gas sales 23,280 17,373 43,163 32,553
Total revenues $ 137,114 $ 118,386 $ 263,018 $ 227,265
Expenses:
Oil and natural gas production $ 42,056 $ 34,265 $ 81,694 $ 66,650
Ad valorem taxes 3,753 2,919 6,649 5,886
Total oil and natural gas production including ad valorem taxes $ 45,809 $ 37,184 $ 88,343 $ 72,536
Production and other taxes $ 8,595 $ 6,771 $ 16,550 $ 13,698
General and administrative excluding LTIP $ 12,669 $ 5,721 $ 19,626 $ 11,017
LTIP expense 2,140 1,343 2,830 2,329
Total general and administrative $ 14,809 $ 7,064 $ 22,456 $ 13,346
Depletion, depreciation, amortization and accretion $ 38,537 $ 39,113 $ 72,234 $ 80,765
Net cash settlements on commodity derivatives:
Net cash settlements (paid) received on oil derivatives $ (6,244) $ (1,934) $ (8,800) $ (1,705)
Net cash settlements (paid) received on natural gas derivatives $ 234 $ 584 $ (820) $ 2,990
Production:
Oil (MBbls) 1,175 1,089 2,310 2,203
Natural gas liquids (MGal) 5,519 3,320 8,881 6,213
Natural gas (MMcf) 4,877 3,649 8,102 7,194
Total (MBoe) 2,119 1,776 3,872 3,550
Average daily production (Boe/d) 23,286 19,516 21,392 19,613
Average sales price per unit (excluding net cash settlements on commodity derivatives):
Oil price (per Bbl) $ 92.54 $ 89.85 $ 91.25 $ 85.43
Natural gas liquids price (per Gal) $ 0.92 $ 0.95 $ 1.02 $ 1.05
Natural gas price (per Mcf) $ 4.77 $ 4.76 $ 5.33 $ 4.53
Combined (per Boe) $ 64.71 $ 66.66 $ 67.93 $ 64.02
Average sales price per unit (including net cash settlements on commodity derivatives):
Oil price (per Bbl) $ 87.22 $ 88.08 $ 87.44 $ 84.66
Natural gas liquids price (per Gal) $ 0.92 $ 0.95 $ 1.02 $ 1.05
Natural gas price (per Mcf) $ 4.82 $ 4.92 $ 5.23 $ 4.94
Combined (per Boe) $ 61.87 $ 65.90 $ 65.44 $ 64.38
Average NYMEX oil index prices per Bbl: $ 103.35 $ 94.05 $ 101.05 $ 94.18
Average NYMEX natural gas index prices per Mcf: $ 4.68 $ 3.34 $ 4.81 $ 3.72
Average unit costs per Boe:
Oil and natural gas production $ 19.85 $ 19.29 $ 21.10 $ 18.77
Ad valorem taxes $ 1.77 $ 1.64 $ 1.72 $ 1.66
Production and other taxes $ 4.06 $ 3.81 $ 4.27 $ 3.86
General and administrative excluding LTIP $ 5.98 $ 3.22 $ 5.07 $ 3.10
Total general and administrative $ 6.99 $ 3.98 $ 5.80 $ 3.76
Depletion, depreciation, amortization and accretion $ 18.19 $ 22.02 $ 18.66 $ 22.75

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, which is the amount to be distributed to our limited partners 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.

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 earned;
  • Equity in EBITDA of equity method investee;
  • Net (gains) losses on commodity derivatives;
  • Net cash settlements received (paid) on commodity derivatives; and
  • Transaction expenses related to acquisitions.

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;
  • Estimated maintenance capital expenditures; and
  • Distributions on Series A and Series B preferred units.

The following table presents a reconciliation of our consolidated net income (loss) to Adjusted EBITDA and Distributable Cash Flow:

Three Months Ended
June 30,
Six Months Ended
June 30,
2014 2013 2014 2013
(dollars in thousands)
Net income (loss) $ (16,488) $ 21,754 $ (15,960) $ 15,049
Plus:
Interest expense 16,225 11,206 30,164 21,898
Income tax expense 278 368 592 578
Depletion, depreciation, amortization and accretion 38,537 39,113 72,234 80,765
Impairment of long-lived assets 2,387 20,774 3,798 22,517
Gain on disposal of assets (3,853) (46) (1,552) (265)
Equity in income of equity method investees (191) (140) (183) (185)
Unit-based compensation expense 2,140 1,344 2,830 2,329
Minimum payments earned in excess of overriding royalty interest (1) 341 10 673 410
EBITDA applicable to equity method investee (2) 241 226 499 226
Net (gains) losses on commodity derivatives 31,433 (25,330) 47,319 (12,325)
Net cash settlements received (paid) on commodity derivatives (6,010) (1,350) (9,620) 1,285
Transaction expenses related to acquisitions 4,911 -- 4,966 --
Adjusted EBITDA $ 69,951 $ 67,929 $ 135,760 $ 132,282
Less:
Cash interest expense 15,590 11,866 29,183 23,444
Cash settlements of LTIP unit awards 560 287 685 1,145
Estimated maintenance capital expenditures (3) 18,200 17,000 36,000 34,000
Distributions on Series A and Series B preferred units 2,193 -- 2,193 --
Distributable Cash Flow (3) $ 33,408 $ 38,776 $ 67,699 $ 73,693
Distributions Attributable to Each Period (4) $ 35,178 $ 33,359 $ 69,429 $ 66,377
Distribution Coverage Ratio (3)(5) 0.95x 1.16x 0.98x 1.11x
(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 are recognized in net income.
(2) EBITDA applicable to equity method investee is defined as the equity method investee's net income or loss plus interest expense and depreciation.
(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 exisiting 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 the aggregate cash distributions declared for the respective period and paid by Legacy within 45 days after the end of each quarter within such period.
(5) We refer to the ratio of Distributable Cash Flow over Distributions Attributable to Each Period ("Available Cash" 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 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 and we must borrow funds or use cash reserves established in prior periods to cover our quarterly distributions. 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

Source:Legacy Reserves LP