Legacy Reserves LP Announces Strategic Alliance With WPX Energy and First Quarter 2014 Results

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MIDLAND, Texas, May 6, 2014 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced it has formed a strategic alliance with WPX Energy, Inc. ("WPX") (NYSE:WPX) through a pending Piceance Basin acquisition for $355 million in cash consideration plus a portion of Legacy's newly-created Incentive Distribution Units ("IDRs") (the "Pending Acquisition"). An investor presentation providing descriptive information has been posted to Legacy's website at www.LegacyLP.com under the Investor Relations tab.

Key characteristics of the Pending Acquisition include:

  • Assets: 2,730 natural gas wells producing primarily from the Williams Fork formation spanning 3 fields within the greater Grand Valley of Garfield County, Colorado
  • Escalating working interest: approximately 29% working interest at closing increases to approximately 37% on January 1, 2015 and approximately 41% on January 1, 2016
  • Operatorship: to remain with WPX, a world-class Rockies operator that currently owns an approximate 98% working interest in the subject properties
  • Internally estimated proved reserves: 276 Bcfe, 100% of which are proved developed producing, and of which 83% are natural gas, 15% are natural gas liquids ("NGLs") and 2% are oil(1)
  • Estimated Q3 2014 production: 63 Mmcfe/d yielding a 12.0 R/P ratio
  • Financial Impact: upon closing, expect significant short-term and long-term accretion to unitholders

The Pending Acquisition has a January 1, 2014 effective date, is subject to customary closing conditions, purchase price adjustments, and the finalization and adoption of an amended and restated partnership agreement(2), and is expected to close before the end of June 2014. WPX will be issued and immediately vest in 10% of the authorized IDRs and have the ability to vest in up to an additional 20% of the authorized IDRs contingent upon future drop-downs to Legacy. The remaining 70% of the authorized IDRs will remain at Legacy in treasury for the benefit of all limited partners until such time as Legacy may make future issuances to other parties.

Legacy's new IDRs are based on a typical construct for master limited partnerships ("MLPs") whereby the IDRs receive an increasing percentage of distributions above defined marginal distribution levels which are provided in the posted investor presentation. Unlike typical MLP incentive distribution rights, the IDRs will not be held at the general partner level. Any distribution allocable to unvested IDRs (90% of the authorized IDRs at closing) shall remain at Legacy for general partnership purposes, including future distributions.

(1) As of 12/31/13 based on SEC pricing as of 12/31/13.

(2) The amended and restated partnership agreement which is necessary to issue the IDRs does not require Legacy unitholder approval.

Legacy today also announced first 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 May 6, 2014. Q1 2014 and subsequent highlights include:

  • 19,478 Boe/d of Production
  • $125.9 million of Revenue
  • $65.8 million of Adjusted EBITDA
  • $34.3 million of Distributable Cash Flow, covering our quarterly distribution by 1.0 times
  • Previously announced acquisitions totaling $112 million in Chaves County, NM and Sheridan County, MT which are expected to add 9.0 MMBoe (95% oil) of internally estimated proved reserves and 890 Boe/d of production. These acquisitions are expected to close in mid-May.
  • On April 10, 2014, priced a $50 million Series A Preferred Unit issuance at 8.0% which now trades on NASDAQ as LGCYP.

Cary D. Brown, Chairman, President and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, commented: "We are excited to announce our new strategic alliance with WPX, a world-class Rockies operator with a deep inventory of MLP-friendly assets. These mature Piceance Basin assets, with an average age of over 9 years, offer long-lived, predictable production and attractive economics due to WPX's unmatched experience and infrastructure. The escalating working interest construct holds production roughly flat over the next few years and provides a stable base for a significant increase to our year-end proved reserves and current production. This transaction delivers on our previously-stated goal of adding gas-weighted properties to our portfolio. Our 143 MMBoe of internally estimated pro forma proved reserves will be comprised of 54% liquids which increases our portfolio diversification and expands our optionality in varying commodity price environments.

"We took great care in negotiating the IDRs with WPX. This newly-created interest will provide a long-term economic incentive for future transactions between the parties. It also allows us to create future alliances with other parties using the remaining 70% of unissued IDRs. Since the creation of Legacy, our management team and Board have been focused on aligning interests with our unitholders. We believe this new IDR interest provides great incentives to its holders while protecting our limited partners with strong, unchanged voting provisions and triggers that are designed to mitigate the dilution that certain other MLPs have experienced when in the highest distribution "splits." Overall, we think this is a great day for Legacy and its unitholders and look forward to closing this transaction and working with WPX in the future to increase value to all involved."

Dan Westcott, Executive Vice President and Chief Financial Officer, commented, "We believe the WPX transaction is a great win for all parties as the established structure incentivizes both parties to profitably and sustainably grow Legacy's distribution. At 4.8 Tcfe of estimated 1P reserves and 16.9 Tcfe of estimated 3P reserves(3), WPX has an enormous inventory of future prospects that either are, or are expected to be, attractive MLP'able assets. The escalating working interest in the Pending Acquisition provides a stable asset base and minimizes our provision for future maintenance capital expenditures thereby providing both immediate and long-term accretion to our unitholders. With our 2014 announced acquisitions, we have meaningfully increased our size and scale, regional footprint and long-term commodity price exposure which should improve our credit profile and future earnings potential. Consistent with our past practice, we plan on hedging a significant portion of our projected production to help ensure our future cash flow. As shown in our newly-updated 2014 Financial Guidance, with the closing of the Pending Acquisition, we are projecting meaningful growth this year. Our Series A Preferred Equity offers us a new instrument to fund our business and, when combined with our to-be-increased borrowing base, we look forward to closing these transactions and increasing unitholder value."

Legacy intends to fund its pending acquisitions with borrowings under its April 2014 $1.5 billion credit facility. Wells Fargo Bank, National Association, as Administrative Agent, has committed to, and is seeking lender approval of, a $950 million borrowing base. Such redetermination is contingent upon approval of all of the banks which is expected to be obtained on or prior to May 22, 2014. In addition to the redetermination, Legacy has already obtained consents from the majority lenders to increase its Debt / EBITDA covenant from 4.0x to 4.5x through June 30, 2015.

Wells Fargo Securities is serving as exclusive financial advisor to Legacy in conjunction with the Pending Acquisition.

(3) As of December 31, 2013, per WPX investor presentation, which excludes the contribution from WPX's international operations and does not give effect to the Pending Acquisition.

Updated 2014 Guidance

The following table sets forth certain assumptions being used by Legacy to estimate its anticipated results of operations for 2014. These estimates do not include any acquisitions of additional oil or natural gas properties. In addition, these estimates are based on, among other things, assumptions of capital expenditure levels, current indications of supply and demand for oil and natural gas and current operating and labor costs. The guidance set forth below does not constitute any form of guarantee, assurance or promise that the matters indicated will actually be achieved. The guidance below sets forth management's best estimate based on current and anticipated market conditions and other factors. While we believe that these estimates and assumptions are reasonable, they are inherently uncertain and are subject to, among other things, significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate, as set forth under "Cautionary Statement Relevant to Forward-Looking Information."

($ in thousands unless otherwise noted) FY 2014E Revised Range
Oil (MBbls) 4,820 -- 4,940
Natural gas liquids (MGal) 24,700 -- 25,300
Natural gas (MMcf) 22,650 -- 23,200
Total (MBoe) 9,183 -- 9,409
Average daily production (Boe/d) 25,159 -- 25,778
Weighted Average NYMEX Differentials:
Oil ($ per Bbl) ($7.00) -- ($8.25)
NGL realization (1) 0.75% -- 0.85%
Natural gas ($ per Mcf) $0.27 -- $0.32
Oil and natural gas production expenses ($/Boe) $18.70 -- $19.60
Ad valorem and production taxes (% of revenue) 9.00% -- 9.50%
G&A excluding LTIP (2) $29,350 -- $30,350
Capital expenditures:
Total development capital expenditures $112,000 -- $118,000
Estimated maintenance capital expenditures $75,300 -- $75,300
(1) Represents the projected percentage of WTI crude oil prices divided by 42, as we report NGLs in gallons.
(2) Excludes Long-Term Incentive Compensation and transaction expenses related to acquisitions.

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

  • Production decreased 1% to 19,478 Boe/d from 19,711 Boe/d primarily due to the natural decline in our Lower Abo assets of approximately 575 Boe/d as well as downtime related to inclement weather. The Lower Abo assets were acquired in our December 2012 acquisition from Concho Resources, Inc. The majority of these wells were drilled in the last three years and thus have a higher natural decline than our more mature properties. These decreases were partially offset by production from our recent acquisitions and development activity throughout the Permian.
  • Average realized price, excluding net cash settlements from commodity derivatives, increased 17% to $71.82 per Boe in 2014 from $61.37 per Boe in 2013. Average realized oil price increased 11% to $89.92 per Bbl in 2014 from $81.11 per Bbl in 2013. This increase of $8.81 per Bbl was attributable to both an increase in the average West Texas Intermediate ("WTI") crude oil price of $4.35 per Bbl as well as lower realized regional differentials. Average realized natural gas price increased 44% to $6.16 per Mcf in 2014 from $4.28 per Mcf in 2013 reflecting a $1.59 increase in the average Henry Hub natural gas index price. Finally, our average realized NGL price increased 2% to $1.18 per gallon in 2014 from $1.16 per gallon in 2013. The large majority of our separately reported NGL production is from our Mid-Continent region.
  • Production expenses, excluding ad valorem taxes, increased 22% to $39.6 million in 2014 from $32.4 million in 2013. Production expenses increased primarily due to additional properties added in 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 also contributed to the increase in production expenses.
  • Legacy's general and administrative expenses excluding unit-based/Long-Term Incentive Plan ("LTIP") compensation expense totaled $7.0 million in 2014 compared to $5.3 million in 2013. This increase was mostly attributable to 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 $3.6 million during 2014 compared to cash receipts of $2.6 million in 2013, a $6.2 million change between the periods.
  • Total development capital expenditures were $21.8 million in 2014 and were heavily weighted towards our Permian Wolfberry drilling. Non-operated capital expenditures comprised 32% 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 April 30, 2014, we had entered into derivatives agreements to receive average NYMEX WTI crude oil prices and NYMEX Henry Hub, Waha, ANR-Oklahoma, and CIG-Rockies natural gas prices as summarized below:

WTI Crude Oil Swaps:
Average Price
Time Period Volumes (Bbls) Price per Bbl Range per Bbl
April-December 2014 2,400,220 $93.66 $87.50 -- $101.50
2015 680,351 $92.48 $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:
Average Short Average Long Average Short
Time Period Volumes (Bbls) Put Price per Bbl Put Price per Bbl Call Price per Bbl
April-December 2014 605,000 $71.59 $96.59 $110.56
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
WTI Crude Oil Enhanced Swaps:
Average Long Average Short Average Swap
Time Period Volumes (Bbls) Put Price per Bbl Put Price per Bbl 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
Average Short Average Swap
Time Period Volumes (Bbls) Put Price per Bbl Price per Bbl
2015 365,000 $70.00 $92.03
Natural Gas Swaps (Henry Hub, WAHA, ANR-Oklahoma and CIG-Rockies):
Time Period Volumes (MMBtu) Average
Price per MMBtu
Range per MMBtu
April-December 2014 7,178,903 $4.39 $3.61 -- $6.47
2015 7,819,300 $4.51 $4.15 -- $5.82
2016 1,419,200 $4.30 $4.12 -- $5.30
Natural Gas 3-Way Collars (Henry Hub):
Average Short Put Average Long Put Average Short Call
Time Period Volumes (MMBtu) Price per MMBtu Price per MMBtu Price per MMBtu
April-December 2014 320,000 $4.00 $4.65 $5.03
2015 1,440,000 $3.25 $4.05 $4.49

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 March 31, 2014, which we plan to file on or about May 6, 2014.

Conference Call

As announced on April 22, 2014, Legacy will host an investor conference call to discuss Legacy's results on Wednesday, May 7, 2014 at 8:00 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 Wednesday, May 14, 2014, by dialing 855-859-2056 or 404-537-3406 and entering replay code 34572156. 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.

Three Months Ended
March 31,
2014 2013
(In thousands, except per unit data)
Oil sales $ 102,055 $ 90,357
Natural gas liquids (NGL) sales 3,965 3,342
Natural gas sales 19,883 15,180
Total revenues 125,903 108,879
Oil and natural gas production 42,534 35,351
Production and other taxes 7,955 6,927
General and administrative 7,647 6,281
Depletion, depreciation, amortization and accretion 33,697 41,652
Impairment of long-lived assets 1,412 1,743
(Gain) loss on disposal of assets 2,301 (219)
Total expenses 95,546 91,735
Operating income 30,357 17,144
Other income (expense):
Interest income 223 8
Interest expense (13,939) (10,692)
Equity in income (loss) of equity method investees (8) 44
Net losses on commodity derivatives (15,886) (13,005)
Other 93 7
Income (loss) before income taxes 840 (6,494)
Income tax expense (314) (211)
Net income (loss) $ 526 $ (6,705)
Income (loss) per unit - basic and diluted $ 0.01 $ (0.12)
Weighted average number of units used in computing net income (loss) per unit --
Basic 57,309 57,077
Diluted 57,367 57,077
(dollars in thousands)
March 31, December 31,
2014 2013
Current assets:
Cash $ 2,972 $ 2,584
Accounts receivable, net:
Oil and natural gas 59,614 47,429
Joint interest owners 15,957 16,532
Other 529 626
Fair value of derivatives 2,266 3,801
Prepaid expenses and other current assets 4,100 3,727
Total current assets 85,438 74,699
Oil and natural gas properties using the successful efforts method, at cost:
Proved properties 2,287,952 2,265,788
Unproved properties 58,611 58,392
Accumulated depletion, depreciation, amortization and impairment (821,762) (788,751)
1,524,801 1,535,429
Other property and equipment, net of accumulated depreciation and amortization of $6,368 and $6,053, respectively 3,604 3,688
Deposits on pending acquisitions 11,200 --
Operating rights, net of amortization of $4,145 and $4,024, respectively 2,871 2,992
Fair value of derivatives 15,925 21,292
Other assets, net of amortization of $10,652 and $10,097, respectively 16,811 17,641
Investments in equity method investees 3,880 4,092
Total assets $ 1,664,530 $ 1,659,833
Current liabilities:
Accounts payable $ 8,147 $ 6,016
Accrued oil and natural gas liabilities 73,872 63,161
Fair value of derivatives 15,403 10,060
Asset retirement obligation 2,610 2,610
Other 19,010 12,043
Total current liabilities 119,042 93,890
Long-term debt 891,149 878,693
Asset retirement obligation 174,345 173,176
Fair value of derivatives 1,438 2,119
Other long-term liabilities 1,528 1,559
Total liabilities 1,187,502 1,149,437
Commitments and contingencies
Unitholders' equity:
Limited partners' equity - 57,340,928 and 57,280,049 units issued and outstanding at March 31, 2014 and December 31, 2013, respectively 476,954 510,322
General partner's equity (approximately 0.03%) 74 74
Total unitholders' equity 477,028 510,396
Total liabilities and unitholders' equity $ 1,664,530 $ 1,659,833
Three Months Ended
March 31,
2014 2013
(In thousands, except per unit data)
Oil sales $ 102,055 $ 90,357
Natural gas liquids (NGL) sales 3,965 3,342
Natural gas sales 19,883 15,180
Total revenues $ 125,903 $ 108,879
Oil and natural gas production $ 39,638 $ 32,385
Ad valorem taxes 2,896 2,966
Total oil and natural gas production including ad valorem taxes $ 42,534 $ 35,351
Production and other taxes $ 7,955 $ 6,927
General and administrative excluding LTIP $ 6,957 $ 5,295
LTIP expense 690 986
Total general and administrative $ 7,647 $ 6,281
Depletion, depreciation, amortization and accretion $ 33,697 $ 41,652
Net cash settlements on commodity derivatives:
Net cash settlements (paid) received on oil derivatives $ (2,556) $ 229
Net cash settlements (paid) received on natural gas derivatives $ (1,054) $ 2,406
Oil (MBbls) 1,135 1,114
Natural gas liquids (MGal) 3,362 2,893
Natural gas (MMcf) 3,226 3,546
Total (MBoe) 1,753 1,774
Average daily production (Boe/d) 19,478 19,711
Average sales price per unit (excluding net cash settlements on commodity derivatives):
Oil price (per Bbl) $ 89.92 $ 81.11
Natural gas liquids price (per Gal) $ 1.18 $ 1.16
Natural gas price (per Mcf) $ 6.16 $ 4.28
Combined (per Boe) $ 71.82 $ 61.37
Average sales price per unit (including net cash settlements on commodity derivatives):
Oil price (per Bbl) $ 87.66 $ 81.32
Natural gas liquids price (per Gal) $ 1.18 $ 1.16
Natural gas price (per Mcf) $ 5.84 $ 4.96
Combined (per Boe) $ 69.76 $ 62.86
NYMEX oil index prices per Bbl:
Average $ 98.68 $ 94.33
NYMEX natural gas index prices per Mcf:
Average $ 4.93 $ 3.34
Average unit costs per Boe:
Oil and natural gas production $ 22.61 $ 18.26
Ad valorem taxes $ 1.65 $ 1.67
Production and other taxes $ 4.54 $ 3.90
General and administrative excluding LTIP $ 3.97 $ 2.98
Total general and administrative $ 4.36 $ 3.54
Depletion, depreciation, amortization and accretion $ 19.22 $ 23.48

Non-GAAP Financial Measures

This press release, the financial tables and other supplemental information include "Adjusted EBITDA" and "Distributable Cash Flow," both of which are non-generally accepted accounting principles ("non-GAAP") measures which may be used periodically by management when discussing our financial results with investors and analysts. The following presents a reconciliation of each of these non-GAAP financial measures to their nearest comparable generally accepted accounting principles ("GAAP") measure.

Adjusted EBITDA and Distributable Cash Flow are presented as management believes they provide additional information 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 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.

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 received 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; and
  • Estimated maintenance capital expenditures.

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

Three Months Ended
March 31,
2014 2013
(dollars in thousands)
Net income (loss) $ 526 $ (6,705)
Interest expense 13,939 10,692
Income tax expense 314 211
Depletion, depreciation, amortization and accretion 33,697 41,652
Impairment of long-lived assets 1,412 1,743
(Gain) loss on disposal of assets 2,301 (219)
Equity in (income) loss of equity method investees 8 (44)
Unit-based compensation expense 690 986
Minimum payments earned in excess of overriding royalty interest (1) 333 400
EBITDA applicable to equity method investee (2) 258 --
Net losses on commodity derivatives 15,886 13,005
Net cash settlements received (paid) received on commodity derivatives (3,610) 2,635
Transaction expenses related to acquisitions 55 --
Adjusted EBITDA $ 65,809 $ 64,356
Cash interest expense 13,594 11,329
Cash settlements of LTIP unit awards 125 858
Estimated maintenance capital expenditures (3) 17,800 17,000
Distributable Cash Flow (3) $ 34,290 $ 35,169
Distributions Attributable to Each Period (4) $ 34,251 $ 33,019
Distribution Coverage Ratio (3)(5) 1.00x 0.94x
(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 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 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