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Legacy Reserves LP Announces First Quarter 2015 Results and Updated Financial Guidance

MIDLAND, Texas, May 6, 2015 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced first quarter results for 2015. Financial results contained herein are preliminary and subject to the final, unaudited financial statements included in Legacy's Form 10-Q to be filed on or about May 8, 2015.

Q1 highlights include:

  • Record production of 33,778 Boe/d, up 3% from Q4 2014 and 73% from Q1 2014
  • Adjusted EBITDA of $62.0 million
  • Distributable Cash Flow of $26.8 million, covering our quarterly distribution by 1.11 times

Paul T. Horne, President and Chief Executive Officer of Legacy commented, "The highlight of this quarter was our rapid response to the current commodity price environment by aggressively driving down our costs. We realized a production expense reduction of approximately 14% from Q4 2014 to Q1 2015. This is the response we needed to see in this challenging commodity price environment and I applaud the team for their excellent work. These efforts contributed to our first quarter distribution coverage of 1.11x and our continued efforts will help us realize coverage in excess of 1.3x on our revised quarterly distribution for the remainder of 2015.

We spent approximately $13 million in Q1 on oil and natural gas development, nearly 45% of our 2015 capital budget, including our first two horizontal Wolfcamp wells. We are encouraged by those initial results and expect continued operational and cost improvement should we resume this program later in the year. On the business development front, we have continued to evaluate our options to monetize portions of our undeveloped Permian acreage and have seen significant private investor interest in a DrillCo structure. As mentioned in our prior release, we are continuing our business development efforts and we remain optimistic in our ability to put our balance sheet to work in making accretive acquisitions that fit our MLP profile."

Dan Westcott, Executive Vice President and Chief Financial Officer of Legacy commented, "On March 27, 2015, we closed our Spring borrowing base redetermination resulting in a reaffirmed $700 million borrowing base. Today we have nearly $588 million of availability under our revolver. We have refined our 2015 financial guidance and, based on those projections, we expect to cover our recently-reduced annualized cash distribution of $1.40 by 1.3x. We also expect to be free cash flow positive in 2015 which should translate into modest debt reduction over the course of the year.

We remain optimistic that continued operational improvements, cost reductions and successful business development opportunities will enable Legacy to deliver significant unitholder value in the current commodity price environment. We remain focused on maximizing unitholder value by protecting our cash flow and yet continue to position ourselves for recovery in commodity prices."

LEGACY RESERVES LP
SELECTED FINANCIAL AND OPERATING DATA
Three Months Ended
March 31,
2015 2014
(In thousands, except per unit data)
Revenues:
Oil sales $ 50,296 $ 102,055
Natural gas liquids sales 4,192 3,965
Natural gas sales 27,051 19,883
Total revenue $ 81,539 $ 125,903
Expenses:
Oil and natural gas production, excluding ad valorem taxes $ 45,944 $ 39,638
Ad valorem taxes $ 3,276 $ 2,896
Total oil and natural gas production $ 49,220 $ 42,534
Production and other taxes $ 4,218 $ 7,955
General and administrative, excluding LTIP $ 7,781 $ 6,957
LTIP expense $ 1,088 $ 690
Total general and administrative $ 8,869 $ 7,647
Depletion, depreciation, amortization and accretion $ 41,068 $ 33,697
Commodity derivative cash settlements:
Oil derivative cash settlements received (paid) $ 32,200 $ (2,556)
Natural gas derivative cash settlements received (paid) $ 8,137 $ (1,054)
Production:
Oil (MBbls) 1,200 1,135
Natural gas liquids (MGal) 9,686 3,362
Natural gas (MMcf) 9,658 3,226
Total (MBoe) 3,040 1,753
Average daily production (Boe/d) 33,778 19,478
Average sales price per unit (excluding derivative cash settlements):
Oil price (per Bbl) $ 41.91 $ 89.92
Natural gas liquids price (per Gal) $ 0.43 $ 1.18
Natural gas price (per Mcf) $ 2.80 $ 6.16
Combined (per Boe) $ 26.82 $ 71.82
Average sales price per unit (including derivative cash settlements):
Oil price (per Bbl) $ 68.75 $ 87.66
Natural gas liquids price (per Gal) $ 0.43 $ 1.18
Natural gas price (per Mcf) $ 3.64 $ 5.84
Combined (per Boe) $ 40.09 $ 69.76
Average WTI oil spot price (per Bbl) $ 48.57 $ 98.68
Average Henry Hub natural gas index price (per Mcf) $ 2.81 $ 4.93
Average unit costs per Boe:
Oil and natural gas production $ 15.11 $ 22.61
Ad valorem taxes $ 1.08 $ 1.65
Production and other taxes $ 1.39 $ 4.54
General and administrative excluding LTIP $ 2.56 $ 3.97
Total general and administrative $ 2.92 $ 4.36
Depletion, depreciation, amortization and accretion $ 13.51 $ 19.22

Financial and Operating Results - First Quarter 2015 Compared to First Quarter 2014

  • Production increased 73% to a record of 33,778 Boe/d from 19,478 Boe/d primarily due to acquisitions in 2014 including our acquisition of non-operated interest in oil and natural gas properties located in the Piceance Basin in Garfield County, Colorado from WPX Energy, Inc ("WPX Acquisition").
  • Average realized price, excluding net cash settlements from commodity derivatives, decreased 63% to $26.82 per Boe in 2015 from $71.82 per Boe in 2014. This decrease in realized prices was primarily 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 53% to $41.91 in 2015 from $89.92 in 2014 driven by a decrease in the average West Texas Intermediate ("WTI") crude oil price of $50.11 per Bbl partially offset by a decrease in realized regional differentials. Average realized natural gas price decreased 55% to $2.80 per Mcf in 2015 from $6.16 per Mcf in 2014. This decrease was a result of the decrease in the average Henry Hub natural gas index price of approximately $2.12 per Mcf as well as the inclusion of lower priced natural gas production from the WPX Acquisition. Finally, our average realized NGL price decreased 64% to $0.43 per gallon in 2015 from $1.18 per gallon in 2014. This decrease is due to the combination of lower commodity prices and the inclusion of lower priced NGL production from the WPX Acquisition.
  • Production expenses, excluding ad valorem taxes, increased 16% to $45.9 million in 2015 from $39.6 million in 2014. On an average cost per Boe basis, production expenses decreased 33% to $15.11 per Boe in 2015 from $22.61 per Boe in 2014, driven primarily by the inclusion of lower cost natural gas properties acquired in the WPX Acquisition as well as reduced expenses across properties that we have owned prior to the WPX Acquisition.
  • Non-cash impairment expense totaled $209.4 million driven by the significant decline in natural gas futures prices during the first quarter of 2015.
  • General and administrative expenses, excluding unit-based Long-Term Incentive Plan ("LTIP") compensation expense totaled $7.8 million in 2015 compared to $7.0 million in 2014. This increase was primarily due to an increase in personnel costs to support recent acquisitions.
  • Cash settlements received on our commodity derivatives during 2015 were $40.3 million compared to cash settlements paid of approximately $3.6 million in 2014.
  • Total development capital expenditures decreased to $13.4 million in 2015 from $21.8 million in 2014. The 2015 activity was comprised mainly of the drilling and completion of two horizontal Wolfcamp wells, completion costs on a horizontal Bone Springs well and capital costs related to CO2 injection properties. Our non-operated capital expenditures were less than 1% of total capital for the quarter compared to 32% in 2014.

Updated Financial Guidance

The following table sets forth certain assumptions used by Legacy to estimate its anticipated results of operations for 2015. 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."

Implied 2015 Range
($ in thousands unless otherwise noted)
Production:
Oil (MBbls) 4,570 -- 4,690
Natural gas liquids (MGal) 38,400 -- 39,400
Natural gas (MMcf) 37,500 -- 38,450
Total (MBoe) 11,734 -- 12,036
Average daily production (Boe/d) 32,148 -- 32,975
Weighted Average NYMEX Differentials:
Oil (per Bbl) $ (7.25) -- $ (6.25)
NGL realization (1) 0.93% -- 0.98%
Natural gas (per Mcf) $0.00 -- $0.05
Expenses:
Oil and natural gas production expenses ($/Boe) $15.00 -- $16.00
Ad valorem and production taxes (% of revenue) 8.25% -- 8.65%
Cash G&A expenses (2) $30,000 -- $32,000
Capital expenditures:
Total development capital expenditures $29,500 -- $30,500
Note: Figures above do not include any assumed acquisitions.
(1) Represents the projected percentage of WTI crude oil prices divided by 42, as we report NGLs in gallons.
(2) Consistent with our definition of Adjusted EBITDA, these figures exclude LTIP expenses. Cash settlements of LTIP (not included herein) impact Distributable Cash Flow.

Commodity Derivative Contracts

We enter into oil and natural gas derivative contracts to help mitigate the risk of changing commodity prices. As of May 6, 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:

WTI Crude Oil Swaps:

Time Period Volumes (Bbls) Average Price per Bbl Price Range per Bbl
April-December 2015 914,735 $79.14 $52.00 -- $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 Put Average Long Put Average Short Call
Time Period Volumes (Bbls) Price per Bbl Price per Bbl Price per Bbl
April-December 2015 997,400 $64.87 $89.60 $111.39
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
April-December 2015 688,000 $77.01 $93.79
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
April-December 2015 2,475,000 $ (1.77) $ (1.65) -- $ (1.90)
2016 1,464,000 $ (1.70) $ (1.65) -- $ (1.75)

Natural Gas Swaps (Henry Hub, Waha and CIG-Rockies):

Average
Time Period Volumes (MMBtu) Price per MMBtu Price Range per MMBtu
April-December 2015 13,963,300 $4.39 $3.98 -- $5.82
2016 1,419,200 $4.30 $4.12 -- $5.30

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
April-December 2015 6,030,000 $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):

April-December 2015
Average
Volumes (MMBtu) Price per MMBtu
NWPL 9,000,000 $ (0.13)
NGPL 360,000 $ (0.15)
SoCal 180,000 $0.19
San Juan 360,000 $ (0.12)
WAHA 4,500,000 $ (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

Our consolidated financial statements and related footnotes will be available in our Form 10-Q which will be filed on or about May 8, 2015.

Ongoing Proxy Process

We are currently seeking the vote of all unitholders through our 2015 proxy process. Our proxy can be found at: http://ir.legacylp.com/proxy.cfm. If you have lost your voting instructions, please contact your bank or broker with whom you hold your units. If you have questions about the voting process, please do not hesitate to contact us at 432-689-5200. We appreciate your support.

Conference Call

As announced on April 20, 2015, Legacy will host an investor conference call to discuss Legacy's results on Thursday, May 7, 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, May 14, 2015, by dialing 855-859-2056 or 404-537-3406 and entering replay code 24970195. 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, 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
March 31,
2015 2014
(In thousands, except per unit data)
Revenues:
Oil sales $ 50,296 $ 102,055
Natural gas liquids (NGL) sales 4,192 3,965
Natural gas sales 27,051 19,883
Total revenues 81,539 125,903
Expenses:
Oil and natural gas production 49,220 42,534
Production and other taxes 4,218 7,955
General and administrative 8,869 7,647
Depletion, depreciation, amortization and accretion 41,068 33,697
Impairment of long-lived assets 209,402 1,412
Loss on disposal of assets 1,941 2,301
Total expenses 314,718 95,546
Operating income (loss) $ (233,179) 30,357
Other income (expense):
Interest income 206 223
Interest expense $ (17,792) $ (13,939)
Equity in income of equity method investees 79 (8)
Net gains (losses) on commodity derivatives 20,480 (15,886)
Other 605 93
Income (loss) before income taxes $ (229,601) 840
Income tax (expense) benefit 747 (314)
Net income (loss) $ (228,854) $ 526
Distributions to Preferred unitholders $ (4,750)
Net income (loss) attributable to unitholders $ (233,604) $ 526
Income (loss) per unit - basic and diluted $ (3.39) $ 0.01
Weighted average number of units used in computing net income (loss) per unit --
Basic 68,921 57,309
Diluted 68,921 57,367
LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
ASSETS
March 31, December 31,
2015 2014
(In thousands)
Current assets:
Cash $ 3,451 $ 725
Accounts receivable, net:
Oil and natural gas 38,658 49,390
Joint interest owners 22,108 16,235
Other 259 237
Fair value of derivatives 104,541 120,305
Prepaid expenses and other current assets 4,403 5,362
Total current assets 173,420 192,254
Oil and natural gas properties using the successful efforts method, at cost:
Proved properties 2,972,336 2,946,820
Unproved properties 48,159 47,613
Accumulated depletion, depreciation, amortization and impairment (1,601,883) (1,354,459)
1,418,612 1,639,974
Other property and equipment, net of accumulated depreciation and amortization of $7,791 and $7,446, respectively 3,560 3,767
Operating rights, net of amortization of $4,620 and $4,509, respectively 2,397 2,508
Fair value of derivatives 28,701 32,794
Other assets, net of amortization of $13,243 and $12,551, respectively 25,647 24,255
Investments in equity method investees 3,053 3,054
Total assets $ 1,655,390 $ 1,898,606
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Accounts payable $ 3,069 $ 2,787
Accrued oil and natural gas liabilities 55,352 78,615
Fair value of derivatives 1,540 2,080
Asset retirement obligation 3,028 3,028
Other 24,204 11,066
Total current liabilities 87,193 97,576
Long-term debt 967,440 938,876
Asset retirement obligation 237,218 223,497
Other long-term liabilities 1,328 1,452
Total liabilities 1,293,179 1,261,401
Commitments and contingencies
Partners' equity
Series A Preferred equity - 2,300,000 units issued and outstanding at March 31, 2015 and December 31, 2014 55,192 55,192
Series B Preferred equity - 7,200,000 units issued and outstanding at March 31, 2015 and December 31, 2014 174,261 174,261
Incentive distribution equity - 100,000 units issued and outstanding at March 31, 2015 and December 31, 2014 30,814 30,814
Limited partners' equity - 68,930,150 and 68,910,784 units issued and outstanding at March 31, 2015 and December 31, 2014, respectively 101,952 376,885
General partner's equity (approximately 0.03%) (8) 53
Total partners' equity 362,211 637,205
Total liabilities and partners' equity $ 1,655,390 $ 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
March 31,
2015 2014
(In thousands)
Net income (loss) $ (228,854) $ 526
Plus:
Interest expense 17,792 13,939
Income tax expense (benefit) (747) 314
Depletion, depreciation, amortization and accretion 41,068 33,697
Impairment of long-lived assets 209,402 1,412
(Gain) loss on disposal of assets 1,941 2,301
Equity in income of equity method investees (79) 8
Unit-based compensation expense 1,088 690
Minimum payments received in excess of overriding royalty interest earned(1) 367 333
Equity in EBITDA of equity method investee(2) 119 258
Net (gains) losses on commodity derivatives (20,480) 15,886
Net cash settlements received (paid) on commodity derivatives 40,337 (3,610)
Transaction expenses related to acquisitions 25 55
Adjusted EBITDA $ 61,979 $ 65,809
Less:
Cash interest expense 17,042 13,594
Cash settlements of LTIP unit awards 125
Estimated maintenance capital expenditures(3) NM* 17,800
Development capital expenditures(4) 13,366 NM*
Distributions on Series A and Series B preferred units 4,750
Distributable Cash Flow(3) $ 26,821 $ 34,290
Distributions Attributable to Each Period(5) $ 24,223 $ 34,251
Distribution Coverage Ratio(3)(6) 1.11x 1.00x
* 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.
(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

Source:Legacy Reserves LP