Legacy Reserves Inc. Announces Third Quarter 2018 Results
MIDLAND, Texas, Oct. 31, 2018 /PRNewswire/ -- Legacy Reserves Inc. ("Legacy") (NASDAQ:LGCY) today announced 2018 third quarter results including the following highlights:
-- Completed our corporate reorganization to become a C-Corp; commenced
trading as Legacy Reserves Inc.;
-- Generated record quarterly oil production of 18,902 Bbls/d, a 5.6%
increase relative to Q2'18, and 31% relative to Q3'17;
-- Brought 7 Permian horizontal wells online during the quarter, totaling
36 of such wells year-to-date;
-- Commenced Wolfcamp drilling in the Delaware Basin in Lea County, NM;
preparing to mobilize Midland Basin horizontal rig from Martin to
Midland County, TX;
-- Completed $21.7 million of asset sales to date since June 30, 2018,
bringing our year-to-date statistics (inclusive of transactions post
quarter-end) to the following:
-- 24 transactions generating $50.9 million of proceeds;
-- 1,454 gross wells producing ~1,600 boe/d;
-- $18.3 million of P&A liability relieved; and
-- Implied 5.9x EBITDA transaction multiple;
-- Completed exchange of $130 million of Senior Notes due 2020 and 2021 for
$130 million of Convertible Senior Notes due 2023 and 105,020 shares of
common stock;
-- Obtained borrowing base reaffirmation at $575 million; and
-- Generated Adjusted EBITDA of $78.4 million, an 8.7% increase relative to
Q2'18, from a net loss of $47.9 million.
Paul T. Horne, Legacy's Chairman of the Board and Chief Executive Officer, commented, "The team completed our first quarter as a C-Corp with a bang as we delivered record oil production that represented 31% year-over-year growth. We continue to focus on our Permian development as we have maintained a rig in Lea County, New Mexico and we are about to move our second rig from Martin to Midland County. Our technical teams continue to hone our well and completion designs and, although basin-wide pressures persist, we are leveraging our long-established relationships to secure services and drive efficiencies. I am also pleased to have validated our theory that the C-Corp would enhance our access to capital as we completed a convertible exchange transaction that extends maturities and provides a path to equitize a significant portion of our debt. As mentioned in today's other press release, I am excited to see our upcoming senior management team continue our growth efforts while targeting free cash flow neutrality."
Dan Westcott, Legacy's President and Chief Financial Officer, commented, "Strong production growth drove Adjusted EBITDA higher despite a challenged Midland oil price this quarter. The team continued to execute, completing several critical, leverage-accretive asset sales. We have also moved the ball forward on several new horizontal prospects and look forward to efficiently developing that resource as we head into year-end planning for 2019."
LEGACY RESERVES INC.
SELECTED FINANCIAL AND OPERATING DATA
Three Months Ended Nine Months Ended
September 30, September 30,
2018 2017 2018 2017
(In thousands, except per unit data)
Revenues:
Oil sales $
98,779 $
59,060 $
291,989 $
154,298
Natural gas liquids (NGL) sales 7,771 6,720 20,902 16,691
Natural gas sales 38,657 41,035 109,076 128,220
Total revenue $
145,207 $
106,815 $
421,967 $
299,209
Expenses:
Oil and natural gas production,
excluding ad valorem taxes $
49,431 $
39,515 $
141,898 $
131,005
Ad valorem taxes 1,873 2,564 6,804 7,093
Total oil and natural gas
production $
51,304 $
42,079 $
148,702 $
138,098
Production and other taxes $
7,721 $
5,475 $
22,705 $
13,779
General and administrative,
excluding transaction costs and
LTIP $
9,852 $
8,418 $
27,357 $
24,087
Transaction costs 1,451 54 4,840 138
LTIP expense 6,475 1,551 32,167 4,931
Total general and administrative $
17,778 $
10,023 $
64,364 $
29,156
Depletion, depreciation,
amortization and accretion $
39,588 $
33,715 $
114,274 $
90,200
Commodity derivative cash settlements:
Oil derivative cash settlements
(paid) received $
(1,702) $
3,102 $
(12,905) $
9,800
Natural gas derivative cash
settlements received $
2,919 $
3,870 $
8,913 $
7,979
Production:
Oil (MBbls) 1,739 1,323 4,915 3,404
Natural gas liquids (MGal) 11,427 11,375 32,003 27,542
Natural gas (MMcf) 15,026 15,771 43,861 46,967
Total (MBoe) 4,515 4,222 12,987 11,888
Average daily production (Boe/
d) 49,076 45,891 47,571 43,542
Average sales price per unit (excluding
derivative cash settlements):
Oil price (per Bbl) $
56.80 $
44.64 $
59.41 $
45.33
Natural gas liquids price (per
Gal) $
0.68 $
0.59 $
0.65 $
0.61
Natural gas price (per Mcf) $
2.57 $
2.60 $
2.49 $
2.73
Combined (per Boe) $
32.16 $
25.30 $
32.49 $
25.17
Average sales price per unit (including
derivative cash settlements):
Oil price (per Bbl) $
55.82 $
46.99 $
56.78 $
48.21
Natural gas liquids price (per
Gal) $
0.68 $
0.59 $
0.65 $
0.61
Natural gas price (per Mcf) $
2.77 $
2.85 $
2.69 $
2.90
Combined (per Boe) $
32.43 $
26.95 $
32.18 $
26.67
Average WTI oil spot price (per
Bbl) $
69.69 $
48.18 $
66.93 $
49.30
Average Henry Hub natural gas
index price (per MMbtu) $
2.93 $
2.95 $
2.95 $
3.01
Average unit costs per Boe:
Oil and natural gas production,
excluding ad valorem taxes $
10.95 $
9.36 $
10.93 $
11.02
Ad valorem taxes $
0.41 $
0.61 $
0.52 $
0.60
Production and other taxes $
1.71 $
1.30 $
1.75 $
1.16
General and administrative
excluding transaction costs and
LTIP $
2.18 $
1.99 $
2.11 $
2.03
Total general and administrative $
3.94 $
2.37 $
4.96 $
2.45
Depletion, depreciation,
amortization and accretion $
8.77 $
7.98 $
8.80 $
7.59
Financial and Operating Results - Three-Month Period Ended September 30, 2018 Compared to Three-Month Period Ended September 30, 2017
-- Production increased 7% to 49,076 Boe/d from 45,891 Boe/d primarily due
to additional oil production from our Permian Basin horizontal drilling
operations and production attributable to the additional working
interests under our amended and restated joint development agreement
with TPG Sixth Street Partners (the "Amended and Restated Development
Agreement"). 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 27% to $32.16 per Boe in 2018 from $25.30 per Boe
in 2017 driven by an increase in oil production as a percentage of total
production and the significant increase in oil prices, partially offset
by widening regional differentials. Average realized oil price increased
27% to $56.80 in 2018 from $44.64 in 2017 driven by an increase in the
average WTI crude oil price of $21.51 per Bbl, partially offset by the
widening Mid-Cush differential. Average realized natural gas price
decreased 1% to $2.57 per Mcf in 2018 from $2.60 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.
These decreases were partially offset by an increase in Permian natural
gas production which is sold inclusive of NGL content and therefore
increases realized pricing for those volumes. Finally, our average
realized NGL price increased 15% to $0.68 per gallon in 2018 from $0.59
per gallon in 2017.
-- Production expenses, excluding ad valorem taxes, increased to $49.4
million in 2018 from $39.5 million in 2017, primarily due to increased
well count due to our Permian horizontal drilling program, increased
working interests under our Amended and Restated Development Agreement
and general cost inflation.
-- Non-cash impairment expense totaled $19.0 million primarily due to the
write down of assets held-for-sale and the decline in natural gas
futures prices.
-- General and administrative expenses, excluding unit-based Long-Term
Incentive Plan ("LTIP") compensation expense, increased to $11.3 million
in 2018 from $8.5 million in 2017 due to a $1.4 million increase in
transaction costs and general cost increases. LTIP compensation expense
increased due to the recent rise in our share price and accelerated
vesting in connection with the Corporate Reorganization. Had the
Corporate Reorganization not occurred, general and administrative
expenses, excluding LTIP, would have decreased by $2.0 million.
-- Cash settlements received on our commodity derivatives during 2018 were
$1.2 million compared to $7.0 million in 2017. The decrease 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 decreased to $31.2 million in
2018 from $93.2 million in 2017. The 2018 activity was comprised mainly
of our Permian horizontal drilling program. The 2017 activity was
comprised mainly of the drilling and completion of joint development
agreement wells. After the acceleration payment under our joint
development agreement, we became responsible for 85% of the parties'
combined interests of all remaining Tranche 1 capital costs to be paid
regardless of when such costs were incurred, resulting in a larger
increase in capital expenditures.
Financial and Operating Results - Nine-Month Period Ended September 30, 2018 Compared to Nine-Month Period Ended September 30, 2017
-- Production increased 9% to 47,571 Boe/d from 43,542 Boe/d primarily due
to additional oil production from our Permian Basin horizontal drilling
operations and production attributable to the additional working
interests under the Amended and Restated Development Agreement. 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 29% to $32.49 per Boe in 2018 from $25.17 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
31% to $59.41 in 2018 from $45.33 in 2017 driven by an increase in the
average WTI crude oil price of $17.63 per Bbl, partially offset by the
widening Mid-Cush differential. Average realized natural gas price
decreased 9% to $2.49 per Mcf in 2018 from $2.73 per Mcf in 2017. This
decrease is a result of the decrease in the average Henry Hub natural
gas index price of approximately $0.06 per Mcf, widening realized
regional differentials and our adoption of ASC 606. Finally, our average
realized NGL price increased 7% to $0.65 per gallon in 2018 from $0.61
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 $141.9
million in 2018 from $131.0 million in 2017. This increase was due to
increased well count due to our Permian horizontal drilling program,
increased working interests under our Amended and Restated Development
Agreement and general cost inflation.
-- Non-cash impairment expense totaled $54.4 million related to the decline
in natural gas prices and the write-down of assets held-for-sale to
their fair market value.
-- General and administrative expenses, excluding unit-based LTIP
compensation expense totaled $32.2 million in 2018 compared to $24.2
million in 2017, reflecting a $4.7 million increase in transaction costs
and general cost increases. LTIP compensation expense increased $27.2
million due to the recent rise in our share price and accelerated
vesting in connection with the Corporate Reorganization. Had the
Corporate Reorganization not occurred, general and administrative
expenses, excluding LTIP, would have decreased by $2.0 million.
-- Cash settlements paid on our commodity derivatives during 2018 were $4.0
million compared to cash receipts of $17.8 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 $171.6 million in
2018 from $141.5 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 October 29, 2018, we had entered into derivative agreements to receive average prices as summarized below.
NYMEX WTI Crude Oil Swaps:
Time
Period
Volumes (Bbls)
Average Price per Price Range per Bbl
Bbl
October-
December
2018 763,600 $54.76 $51.20 $63.68
2019 3,285,000 $61.33 $57.15 $67.65
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.
Average Long
Average Short
Time
Period
Volumes (Bbls)
Put Price per Bbl
Call Price per Bbl
October-
December
2018 391,000 $47.06 $60.29
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.
Average Long Put
Average Short Put
Average Swap
Time Period
Volumes (Bbls)
Price per Bbl
Price per Bbl
Price per Bbl
October-December
2018 32,200 $57.00 $82.00 $90.50
Midland-to-Cushing WTI Crude Oil Differential Swaps:
Time
Period
Volumes (Bbls)
Average Price per Price Range per Bbl
Bbl
October-
December
2018 1,012,000 $(1.13) $(1.25) $(0.80)
2019 2,193,000 $(3.62) $(5.60) $(1.15)
Midland-to-Cushing WTI Crude Oil Differential Enhanced Swaps
Time Period
Volumes (Bbls)
Average Short Price
Average Swap Price
Call per Bbl per Bbl
2019 1,460,000 $70.00 $(2.91)
NYMEX Natural Gas Swaps (Henry Hub):
Average Price Range per
Time
Period
Volumes (MMBtu)
Price per MMBtu MMBtu
October-
December
2018 9,080,000 $3.23 $3.04 $3.39
2019 25,800,000 $3.36 $3.29 $3.39
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 October 31, 2018.
Conference Call
As announced on October 17, 2018, Legacy will host an investor conference call to discuss Legacy's results on Thursday, November 1, 2018 at 9:00 a.m. (Central Time). Those wishing to participate in the conference call should dial 888-346-9287. A replay of the call will be available through Thursday, November 8, 2018, by dialing 877-344-7529 and entering replay code 10125178. 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.LegacyReserves.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 Inc.
Legacy is an independent energy company engaged in the development, production and acquisition of oil and natural gas properties in the United States. Its current operations are focused on the horizontal development of unconventional plays in the Permian Basin and the cost-efficient management of shallow-decline oil and natural gas wells in the Permian Basin, East Texas, Rocky Mountain and Mid-Continent regions. Additional information is available at www.LegacyReserves.com.
Cautionary Statement Relevant to Forward-Looking Information
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, including, without limitation, statements regarding the expected future growth and dividends of the company, and plans and objectives of management for future operations. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that Legacy expects, believes or anticipates will or may occur in the future, are forward-looking statements. 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 forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside the control of Legacy, which could cause results to differ materially from those expected by management of Legacy. Such risks and uncertainties include, but are not limited to, 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 Legacy's and Legacy LP's filings with the U.S. Securities and Exchange Commission, including its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. 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 INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2018 2017 2018 2017
(In thousands, except per share /unit data)
Revenues:
Oil sales $
98,779 $
59,060 $
291,989 $
154,298
Natural gas liquids (NGL)
sales 7,771 6,720 20,902 16,691
Natural gas sales 38,657 41,035 109,076 128,220
Total revenues 145,207 106,815 421,967 299,209
Expenses:
Oil and natural gas
production 51,304 42,079 148,702 138,098
Production and other taxes 7,721 5,475 22,705 13,779
General and administrative 17,778 10,023 64,364 29,156
Depletion, depreciation,
amortization and accretion 39,588 33,715 114,274 90,200
Impairment of long-lived
assets 18,994 14,665 54,375 24,548
(Gains) losses on disposal of
assets 7,368 (2,034) (14,172) 3,491
Total expenses 142,753 103,923 390,248 299,272
Operating income (loss) 2,454 2,892 31,719 (63)
Other income (expense):
Interest income 16 35 31 44
Interest expense (29,383) (23,621) (85,340) (64,368)
Gain on extinguishment of
debt 12,107 63,800
Equity in income (loss) of
equity method investees (30) (10) 12
Net gains (losses) on
commodity derivatives (30,867) (13,309) (41,886) 35,876
Other 350 403 623 765
Loss before income taxes (45,353) (33,600) (31,063) (27,734)
Income tax expense (2,499) (266) (3,116) (837)
Net loss $
(47,852) $
(33,866) $
(34,179) $
(28,571)
Loss per share /unit -basic
& diluted $
(0.46) $
(0.34) $
(0.33) $
(0.29)
Weighted average number of shares /units
used in computing net loss per share /
unit -
Basic 104,637 100,206 104,336 99,985
Diluted 104,637 100,206 104,336 99,985
===
LEGACY RESERVES INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
ASSETS
September 30, December 31,
2018 2017
(In thousands)
Current assets:
Cash $
3,305 $
1,246
Accounts receivable, net:
Oil and natural gas 61,109 62,755
Joint interest owners 14,516 27,420
Other 2 2
Fair value of derivatives 19,228 13,424
Prepaid expenses and other current
assets 10,231 7,757
Total current assets 108,391 112,604
Oil and natural gas properties using the
successful efforts method, at cost:
Proved properties 3,497,024 3,529,971
Unproved properties 28,897 28,023
Accumulated depletion, depreciation,
amortization and impairment (2,192,877) (2,204,638)
1,333,044 1,353,356
Other property and equipment, net of
accumulated depreciation and
amortization of $12,179 and $11,467,
respectively 2,464 2,961
Operating rights, net of amortization of
$6,034 and $5,765, respectively 983 1,251
Fair value of derivatives 3,183 14,099
Other assets 3,671 8,811
Total assets $
1,451,736 $
1,493,082
LIABILITIES AND STOCKHOLDERS' DEFICIT / PARTNERS' DEFICIT
Current liabilities:
Current debt, net 527,391
$
Accounts payable 7,838 13,093
Accrued oil and natural gas liabilities 83,216 81,318
Fair value of derivatives 39,072 18,013
Asset retirement obligation 3,214 3,214
Other 43,163 29,172
Total current liabilities 703,894 144,810
Long-term debt, net 755,784 1,346,769
Asset retirement obligation 261,260 271,472
Fair value of derivatives 12,114 1,075
Other long-term liabilities 641 643
Total liabilities 1,733,693 1,764,769
Commitments and contingencies
Partners' deficit
Series A Preferred equity -2,300,000
units issued and outstanding at
December 31, 2017 55,192
Series B Preferred equity -7,200,000
units issued and outstanding at
December 31, 2017 174,261
Incentive distribution equity -100,000
units issued and outstanding at
December 31, 2017 30,814
Limited partners' deficit -72,594,620
units issued and outstanding at
December 31, 2017 (531,794)
General partner's deficit (approximately
0.02%) (160)
Common stock, $0.01 par value;
945,000,000 shares authorized,
106,113,000 shares outstanding at
September 30, 2018 1,061
Additional paid-in capital 13,471
Accumulated deficit (296,489)
Total stockholders' deficit (281,957) (271,687)
Total liabilities and stockholders' /
partners' deficit $
1,451,736 $
1,493,082
Non-GAAP Financial Measures
"Adjusted EBITDA" is a non-generally accepted accounting principles ("non-GAAP") measure which may be used periodically by management when discussing our financial results with investors and analysts. The following presents a reconciliation of this non-GAAP financial measure to its nearest comparable generally accepted accounting principles ("GAAP") measure.
Adjusted EBITDA is presented as management believes it provides additional information concerning the performance of our business and is 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 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.
Certain factors impacting Adjusted EBITDA 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.
"Adjusted EBITDA" should not be considered as an alternative 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 loss to Adjusted EBITDA:
Three Months Ended Nine Months Ended
September 30, September 30,
2018 2017 2018 2017
(In thousands)
Net loss $
(47,852) $
(33,866) $
(34,179) $
(28,571)
Plus:
Interest expense 29,383 23,621 85,340 64,368
Gain on extinguishment of debt (12,107) (63,800)
Income tax expense 2,499 266 3,116 837
Depletion, depreciation, amortization
and accretion 39,588 33,715 114,274 90,200
Impairment of long-lived assets 18,994 14,665 54,375 24,548
(Gain) loss on disposal of assets 7,368 (2,034) (14,172) 3,491
Equity in (income) loss of equity
method investees 30 10 (12)
Share-based compensation expense 6,475 1,551 32,167 4,931
Minimum payments received in excess of
overriding royalty interest earned(1) 516 512 1,373 1,427
Net (gains) losses on commodity
derivatives 30,867 13,309 41,886 (35,876)
Net cash settlements (paid) received on
commodity derivatives 1,217 6,972 (3,992) 17,779
Transaction costs 1,451 54 4,840 138
Adjusted EBITDA(2) $
78,429 $
58,765 $
221,238 $
143,260
(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) Had the Corporate Reorganization not
occurred on September 20, 2018,
EBITDA would have increased to $80.4
million and $223.2 million for the
three and nine month periods ending
September 30, 2018, respectively.
CONTACT: Legacy Reserves Inc.
Dan Westcott
President and Chief
Financial Officer
(432) 689-5200
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