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
September 30,
|
|
Nine Months
Ended
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
Bbl
|
|
Price Range per
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
Bbl
|
|
Price Range per
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
Call per Bbl
|
|
Average Swap
Price
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,
2018
|
|
December 31,
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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SOURCE Legacy Reserves Inc.