Legacy Reserves LP Announces Second Quarter 2018 Results

MIDLAND, Texas, Aug. 1, 2018 /PRNewswire/ — Legacy Reserves LP (“Legacy”) (NASDAQ:LGCY) today announced second quarter results for 2018 including the following highlights:

• Generated record quarterly oil production of 17,901 Bbls/d, a 4% increase relative to Q1’18;
• Commenced Wolfcamp drilling in Martin County and began preparing surface locations ahead of a rig move into Midland County;
• Brought 9 Permian horizontal wells online during the quarter, bringing the total to 29 Permian horizontal wells brought online year-to-date;
• Completed multiple strategic Permian acreage trades requiring no net cash outlay which enhanced projected economics for 33 gross drilling locations:
• Increased average lateral lengths for 3 of Legacy’s core Midland Basin tracts by 58%, resulting in an increase in net lateral footage by 45,000 feet;
• Generated a net loss of $50.7 million;
• Generated Adjusted EBITDA of $72.1 million; and
• Subsequent to quarter-end, Legacy achieved meaningful progress related to our previously announced Corporate Reorganization including:
• Entered into a Stipulation and Agreement of Settlement (the “Settlement Agreement”) to settle the previously announced class action lawsuit filed by holders of Preferred Units; and
• Now anticipate filing definitive proxy statement and commencing unitholder solicitation in the coming days incorporating a special meeting of unitholders to approve the Corporate Reorganization on September 19, 2018 for unitholders of record as of the close of business on July 26, 2018.

Paul T. Horne, Chairman of the Board and Chief Executive Officer of Legacy’s general partner, commented, “I am really proud of the strong results reported by all of our business units this quarter. Our business development and land teams created significant potential value by completing several complicated trades involving a puzzle of 11 tracts across the Permian Basin and many counterparties. Our team fit those pieces together in an optimized fashion that substantially improves the projected economics of some of our core inventory. Our operations team continues to find ways to improve leasehold economics by leveraging our longstanding Permian position. We remain committed to our lease-wide development approach, focused on maximizing return on investment, production, reserves and cash flow and we look forward to continuing this program as we transition to a C-Corp.”

Dan Westcott, President and Chief Financial Officer of Legacy’s general partner, commented, “Our team continues to execute and we are glad to report oil production growth that drives growth in EBITDA. While we have limited control over the widening of our oil differentials that occurred this quarter due to the widening of Mid-Cush basis, we are happy that we have hedged most of that exposure in 2018 and a bit of it in 2019. We gained good momentum in the field this quarter, and when combined with our expanded Permian Basin footprint, we believe we are well-positioned for success and are excited to realize Legacy’s transition to becoming a growth-oriented development company.”

Financial and Operating Results – Three-Month Period Ended June 30, 2018 Compared to Three-Month Period Ended June 30, 2017

• Production increased 12% to 47,527 Boe/d from 42,275 Boe/d primarily due to additional oil production from our Permian Basin horizontal drilling operations and production attributable to the additional working interests that reverted to us in connection with making an acceleration payment on August 1, 2017 (the “Acceleration Payment”) under our amended and restated joint development agreement with TSSP. This was partially offset by natural production declines and individually immaterial divestitures completed in 2018 and 2017.
• Average realized price, excluding net cash settlements from commodity derivatives, increased 33% to $32.20 per Boe in 2018 from $24.13 per Boe in 2017 driven by the significant increase in oil prices and an increase in oil production as a percentage of total production, partially offset by widening regional differentials. Average realized oil price increased 39% to $61.26 in 2018 from $44.15 in 2017 driven by an increase in the average WTI crude oil price of $19.97 per Bbl, partially offset by the widening Mid-Cush differential. Average realized natural gas price decreased 13% to $2.32 per Mcf in 2018 from $2.68 per Mcf in 2017. This decrease is primarily the result of a decrease in NYMEX pricing, widening realized regional differentials and our adoption of ASC 606. Finally, our average realized NGL price decreased 12% to $0.51 per gallon in 2018 from $0.58 per gallon in 2017 due to increased volumes with a higher percentage of lower-priced ethane.
• Production expenses, excluding ad valorem taxes, increased to $46.9 million in 2018 from $42.3 million in 2017, primarily due to additional costs associated with increased production related to our Permian horizontal drilling program as well as increased working interests following the Acceleration Payment. On an average cost per Boe basis, production expenses excluding ad valorem taxes decreased 1% to $10.84 per Boe in 2018 from $10.99 per Boe in 2017.
• Non-cash impairment expense totaled $35.4 million driven by the decline in natural gas futures prices.
• General and administrative expenses, excluding unit-based Long-Term Incentive Plan (“LTIP”) compensation expense, increased to $9.6 million in 2018 from $7.1 million in 2017 due to a $1.5 million increase in transaction costs and general cost increases. LTIP compensation expense increased $11.4 million due to the recent rise in our unit price.
• Cash settlements paid on our commodity derivatives during 2018 were $2.4 million compared to cash receipts of $6.6 million in 2017. The change in cash settlements is a result of higher commodity prices, reduced nominal volumes hedged in Q2 2018 compared to Q2 2017 and lower contracted hedge prices. This was partially offset by an increase in cash receipts of our Mid-Cush derivatives.
• Total development capital expenditures increased to $80.7 million in 2018 from $24.6 million in 2017. The 2018 activity was comprised mainly of our Permian horizontal drilling program.

Financial and Operating Results – Six-Month Period Ended June 30, 2018 Compared to Six-Month Period Ended June 30, 2017

• Production increased 11% to 46,807 Boe/d from 42,348 Boe/d primarily due to additional oil production from our Permian Basin horizontal drilling operations and production attributable to the additional working interests that reverted to us in connection with the August 1, 2017 Acceleration Payment. This was partially offset by natural production declines and individually immaterial divestitures completed in 2018 and 2017.
• Average realized price, excluding net cash settlements from commodity derivatives, increased 30% to $32.67 per Boe in 2018 from $25.10 per Boe in 2017 driven by the significant increase in oil prices and an increase in oil production as a percentage of total production, partially offset by widening regional differentials. Average realized oil price increased 33% to $60.83 in 2018 from $45.77 in 2017 driven by an increase in the average WTI crude oil price of $15.70 per Bbl, partially offset by the widening Mid-Cush differential. Average realized natural gas price decreased 13% to $2.44 per Mcf in 2018 from $2.79 per Mcf in 2017. This decrease is a result of the decrease in the average Henry Hub natural gas index price of approximately $0.09 per Mcf and widening realized regional differentials. Finally, our average realized NGL price increased 3% to $0.64 per gallon in 2018 from $0.62 per gallon in 2017 due to higher commodity prices partially offset by increased volumes with a higher percentage of lower-priced ethane.
• Our production expenses, excluding ad valorem taxes, increased to $92.5 million in 2018 from $91.5 million in 2017. This increase was due to increased production related to our Permian horizontal drilling program as well as increased working interests following the Acceleration Payment, partially offset by cost containment efforts. On an average cost per Boe basis, production expenses decreased 9% to $10.91 per Boe in 2018 from $11.94 per Boe in 2017.
• Non-cash impairment expense totaled $35.4 million driven by the decline in natural gas futures prices.
• General and administrative expenses, excluding unit-based LTIP compensation expense totaled $20.9 million in 2018 compared to $15.8 million in 2017, reflecting a $3.3 million increase in transaction costs and general cost increases. LTIP compensation expense increased $21.8 million due to the recent rise in our unit price.
• Cash settlements paid on our commodity derivatives during 2018 were $5.2 million compared to cash receipts of $10.8 million in 2017. The change in cash settlements is a result of higher commodity prices, reduced nominal volumes hedged in 2018 compared to 2017 and lower contracted hedge prices. This was partially offset by an increase in cash receipts of our Mid-Cush derivatives.
• Total development capital expenditures increased to $140.4 million in 2018 from $48.3 million in 2017. The 2018 activity was comprised mainly of our Permian horizontal drilling program.

Commodity Derivative Contracts

We enter into oil and natural gas derivative contracts to help mitigate the risk of changing commodity prices. As of July 31, 2018, we had entered into derivative agreements to receive average prices as summarized below.

NYMEX WTI Crude Oil Swaps:

NYMEX WTI Crude Oil Costless Collars. At an annual WTI market price of $40.00, $50.00 and $65.00, the summary positions below would result in a net price of $47.06, $50.00 and $60.29, respectively for 2018.

NYMEX WTI Crude Oil Enhanced Swaps. At an annual average WTI market price of $40.00, $50.00 and $65.00, the summary positions below would result in a net price of $65.50, $65.50 and $73.50, respectively for 2018.

Midland-to-Cushing WTI Crude Oil Differential Swaps:

NYMEX Natural Gas Swaps (Henry Hub):

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 August 7, 2018.

Credit Agreement Waiver

On July 31, 2018, the lenders for our credit agreement agreed to waive our compliance with the ratio of consolidated current assets to consolidated current liabilities covenant contained in the credit agreement for the fiscal quarter ended June 30, 2018.

Conference Call

As announced on July 18, 2018, Legacy will host an investor conference call to discuss Legacy’s results on Thursday, August 2, 2018 at 9:00 a.m. (Central Time). Those wishing to participate in the conference call should dial 877-870-4263. A replay of the call will be available through Thursday, August 9, 2018, by dialing 877-344-7529 and entering replay code 10122434. Those wishing to listen to the live or archived webcast via the Internet should go to the Investor Relations tab of our website at www.LegacyLP.com. Following our prepared remarks, we will be pleased to answer questions from securities analysts and institutional portfolio managers and analysts; the complete call is open to all other 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 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.

Additional Information for Holders of Legacy Units and Where to Find It

Although Legacy has suspended distributions to both the 8% Series A and Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”), such distributions continue to accrue. Pursuant to the terms of Legacy’s partnership agreement, Legacy is required to pay or set aside for payment all accrued but unpaid distributions with respect to the Preferred Units prior to or contemporaneously with making any distribution with respect to Legacy’s units. Accruals of distributions on the Preferred Units are treated for tax purposes as guaranteed payments for the use of capital that will generally be taxable to the holders of such Preferred Units as ordinary income even in the absence of contemporaneous distributions.

In addition, Legacy’s unitholders, j