MIDLAND, Texas, Feb. 21,
2018 /PRNewswire/ -- Legacy Reserves LP ("Legacy") (NASDAQ:LGCY)
today announced fourth quarter and annual results for 2017, which
included the following highlights:
- Generated record quarterly production of 49,185 Boe/d, a 7%
increase relative to Q3'17, and record annual production of 44,967
Boe/d.
- Generated record quarterly oil production of 17,696 Bbls/d, a
23% increase relative to Q3'17 and record annual oil production of
13,786 Bbls/d.
- Generated a net loss of $53.9
million for the year ended December
31, 2017.
- Generated Adjusted EBITDA of $226.2
million for the year ended December
31, 2017, representing a 45% year-over-year increase.
- Amended and restated our Joint Development Agreement ("JDA")
with TPG Sixth Street Partners ("TSSP") and made an $141 million Acceleration Payment (the
"Acceleration Payment") increasing our working interest from 20% to
85% in Tranche 1 wells and from 20% to 66.3% in a subsequent
tranche of wells.
- Entered into an agreement on December
31, 2017 to repurchase $187
million of our 6.625% Senior unsecured notes due 2021 (the
"2021 Senior Notes") at $0.70 per
$1.00 of principal amount. This
transaction settled on January 5,
2018.
- Entered into an agreement to amend our second lien term loan
credit agreement to increase the amount of aggregate commitments
from $300 million to $400 million and extend the availability of those
commitments to October 25, 2019
effective January 5, 2018.
- Meaningfully improved our credit statistics including a
reduction in our Total Debt / EBITDA by 2.1x as calculated on a pro
forma basis under our credit documents relative to year-end
2016.
- Brought online an additional 5 and 30 horizontal Permian wells
during the quarter and year, respectively, with an inventory of 21
drilled but uncompleted wells at December
31, 2017.
Paul T. Horne, Chairman of the
Board, President and Chief Executive Officer, commented, "We are
excited about the progress we made in 2017 toward transitioning to
a growth-oriented development company with an improved balance
sheet. The Acceleration Payment, bond repurchase, expanded second
lien commitments, continued efficient Permian horizontal
development and prudent PDP management were instrumental in
charting this path. While we are extremely proud of these
cornerstone 2017 achievements, significant strides remain for us to
fully realize our goals. As such, we continue to evaluate and
opportunistically pursue alternatives that will enhance equity
value."
Dan Westcott, Executive Vice
President and Chief Financial Officer, commented, "2017 was an
incredibly active year as we positioned Legacy for meaningful oil
production growth that compressed leverage metrics and will drive
equity value. We also reduced leverage by capturing discount in our
bonds which allowed us to gain meaningful voting power in our
senior notes. Undoubtedly, our operations team was the driving
force in delivering our record-beating results through their
continued capital-efficient horizontal development of our Permian
resources and economic operation of our large PDP base. Focus on
both of these arenas provided the foundation for our
guidance-beating production of 49,185 Boe/d in Q4 and Adjusted
EBITDA of $226.2 million in 2017 and
is critical to the ongoing success of Legacy."
"While in 2016 we aimed to reduce debt outstanding, we shifted
in 2017 to improve our overall credit metrics. These efforts
decreased our year-over-year pro forma Total Debt / EBITDA by 2.1x.
For 2018, our new financial guidance suggests Adjusted EBITDA of
$330 million, a 46% increase compared
to 2017. This tremendous growth hinges on our commitment to
operational excellence which should continue to compress our
leverage metrics as we evaluate and opportunistically pursue
alternatives to change our legal and tax status, materially reduce
our outstanding debt, extend our debt maturities, and otherwise
position the company for long-term growth. We have a big year ahead
of us and are excited for the opportunity to grow equity value
through these efforts."
Proved Reserves
The following information represents estimates of our proved
reserves as of December 31, 2017 which have been prepared in
compliance with the SEC rules using an average WTI price, as posted
by Plains Marketing L.P., of $47.79
per Bbl for oil and an average natural gas price, as posted by
Platts Gas Daily, of $2.98 per
MMBtu.
Operating
Regions
|
|
Oil
(MBbls)
|
|
Natural
Gas
(MMcf)
|
|
NGLs
(MBbls)
|
|
Total
(MBoe)
|
|
%
Liquids
|
|
%
PDP
|
|
%
Total
|
|
Standardized
Measure
($
thousands)
|
Permian
Basin
|
|
43,023
|
|
|
125,810
|
|
|
1,433
|
|
|
65,424
|
|
|
68
|
%
|
|
87
|
%
|
|
36
|
%
|
|
$
|
750,730
|
|
East Texas
|
|
79
|
|
|
343,720
|
|
|
216
|
|
|
57,582
|
|
|
1
|
%
|
|
98
|
%
|
|
32
|
%
|
|
197,186
|
|
Rocky
Mountain
|
|
5,987
|
|
|
234,176
|
|
|
5,338
|
|
|
50,354
|
|
|
22
|
%
|
|
99
|
%
|
|
28
|
%
|
|
182,181
|
|
Mid-Continent
|
|
2,057
|
|
|
12,428
|
|
|
2,465
|
|
|
6,593
|
|
|
69
|
%
|
|
96
|
%
|
|
4
|
%
|
|
42,051
|
|
Total
|
|
51,146
|
|
|
716,134
|
|
|
9,452
|
|
|
179,953
|
|
|
34
|
%
|
|
94
|
%
|
|
100
|
%
|
|
$
|
1,172,148
|
|
2018 Capital Program By Category
|
Gross
|
|
Net
|
|
Percent of
Net
|
|
(In
millions)
|
|
|
Horizontal Permian
development
|
$
|
290
|
|
|
$
|
203
|
|
|
91
|
%
|
Other
drilling
|
34
|
|
|
5
|
|
|
2
|
%
|
Other
workovers
|
16
|
|
|
12
|
|
|
5
|
%
|
East Texas
(workovers, G&P, facilities)
|
3
|
|
|
3
|
|
|
1
|
%
|
Other
facilities
|
2
|
|
|
2
|
|
|
1
|
%
|
Total capital
expenditures
|
$
|
345
|
|
|
$
|
225
|
|
|
100
|
%
|
We serve as operator of approximately 98% of our anticipated
capital program, and accordingly, maintain significant control of
the capital program budget and may deviate materially from the
figures above based on market conditions (or otherwise).
Updated 2018 Guidance
The following table sets forth certain assumptions used by
Legacy to estimate its anticipated results of operations for 2018
based on the aforementioned expected 2018 capital program. 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."
|
|
FY 2018E
Range
|
|
|
($ in thousands
unless otherwise noted)
|
Production:
|
|
|
|
|
Oil
(Bbls/d)
|
|
19,000
|
-
|
21,400
|
Natural gas liquids
(Bbls/d)
|
|
1,875
|
-
|
2,075
|
Natural gas
(MMcf/d)
|
|
162
|
-
|
176
|
Total
(Boe/d)
|
|
47,875
|
-
|
52,808
|
|
|
|
|
|
Weighted average
NYMEX differentials:
|
|
|
|
|
Oil (per
Bbl)
|
|
$(4.00)
|
-
|
$(3.25)
|
NGL
realization(1)
|
|
52%
|
-
|
63%
|
Natural gas (per
Mcf)
|
|
$(0.35)
|
-
|
$(0.20)
|
|
|
|
|
|
Expenses:
|
|
|
|
|
Lease operating
expenses(2)
|
|
$175,000
|
-
|
$195,000
|
Ad valorem and
production taxes (% of revenue)
|
|
7.40%
|
-
|
7.90%
|
Cash G&A
expenses(3)
|
|
$34,000
|
-
|
$38,000
|
|
|
|
|
|
Adjusted
EBITDA(4):
|
|
$300,000
|
-
|
$360,000
|
|
|
(1)
|
Represents the
projected percentage of assumed WTI crude oil prices.
|
(2)
|
Excludes ad valorem
and production taxes.
|
(3)
|
Consistent with our
definition of Adjusted EBITDA, these figures exclude LTIP and
transaction costs.
|
(4)
|
Adjusted EBITDA is a
Non-GAAP financial measure. This measure does not include pro forma
adjustments permitted under our credit agreements relating to
acquired and divested oil or gas properties. A reconciliation of
this measure to the nearest comparable GAAP measure is available on
our website.
|
Note: Figures above
assume NYMEX strip pricing at 2/15/2018 (2018 Avg Oil $59.59 /
$2.80 Gas).
|
Dan Westcott's Promotion to
President
Effective March 1, 2018 Dan
Westcott, Legacy's Chief Financial Officer will also assume the
position of Legacy's President. Effective March 1, 2018, Paul
Horne has resigned his position as President but will remain
Chairman and Chief Executive Officer.
Mr. Horne commented, "Dan has done an outstanding job helping
the company navigate the challenging landscape we have faced over
the past three years. His focus and diligence on improving our
financial condition and balance sheet are evident in our results.
We are very excited about the future of Legacy and the critical
role he has played and will play in that future. Dan's
promotion to President acknowledges both and is well deserved."
Schedules K-1 Available
Legacy also announced today that it has completed the 2017 tax
packages for unitholders of LGCY, LGCYP and LGCYO including
Schedules K-1. Schedules K-1 for LGCYP and LGCYO each reflect
$0.166667 of income for each month
such security was owned in 2017 ($2.00 in total assuming a full year of ownership)
irrespective of the fact that (i) no 2017 distributions were paid
and (ii) the Partnership generated a net loss in 2017. Each holder
of LGCY, LGCYO and LGCYP is encouraged to consult with its tax
advisor with respect to the Schedule K-1 information and individual
tax circumstances.
The tax packages are currently available online and may be
accessed via Legacy's website at www.LegacyLP.com by clicking on
the "Tax Information" link on the website. Legacy will begin
mailing the Schedules K-1 to unitholders on Friday, February 23, 2018. For additional
information, unitholders may also contact Legacy's K-1 Partner Data
Link call center toll free at (877) 504-5606 between 8:00 a.m. and 5:00 p.m. CST Monday through
Friday.
LEGACY RESERVES
LP
|
SELECTED FINANCIAL
AND OPERATING DATA
|
(Unaudited)
|
|
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December
31,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
(In thousands,
except per unit data)
|
Revenues
|
|
|
|
|
|
|
|
Oil sales
|
$
|
85,150
|
|
|
$
|
42,164
|
|
|
$
|
239,448
|
|
|
$
|
152,507
|
|
Natural gas liquids
sales
|
8,105
|
|
|
5,574
|
|
|
24,796
|
|
|
15,406
|
|
Natural gas
sales
|
43,837
|
|
|
43,853
|
|
|
172,057
|
|
|
146,444
|
|
Total
revenues
|
$
|
137,092
|
|
|
$
|
91,591
|
|
|
$
|
436,301
|
|
|
$
|
314,357
|
|
Expenses:
|
|
|
|
|
|
|
|
Oil and natural gas
production
|
$
|
42,594
|
|
|
$
|
41,456
|
|
|
$
|
173,599
|
|
|
$
|
169,755
|
|
Ad valorem
taxes
|
2,527
|
|
|
172
|
|
|
9,620
|
|
|
9,578
|
|
Total
|
$
|
45,121
|
|
|
$
|
41,628
|
|
|
$
|
183,219
|
|
|
$
|
179,333
|
|
Production and other
taxes
|
$
|
6,046
|
|
|
$
|
4,318
|
|
|
$
|
19,825
|
|
|
$
|
14,267
|
|
General and
administrative excluding transaction costs and LTIP
|
$
|
9,919
|
|
|
$
|
8,237
|
|
|
$
|
34,006
|
|
|
$
|
31,196
|
|
Transaction
costs
|
8,631
|
|
|
4,158
|
|
|
8,769
|
|
|
5,245
|
|
LTIP
expense
|
1,666
|
|
|
1,586
|
|
|
6,597
|
|
|
7,198
|
|
Total general and
administrative
|
$
|
20,216
|
|
|
$
|
13,981
|
|
|
$
|
49,372
|
|
|
$
|
43,639
|
|
Depletion,
depreciation, amortization and accretion
|
$
|
36,738
|
|
|
$
|
39,719
|
|
|
$
|
126,938
|
|
|
$
|
150,414
|
|
Commodity derivative
cash settlements:
|
|
|
|
|
|
|
|
Oil derivative cash
settlements received
|
$
|
2,040
|
|
|
$
|
7,030
|
|
|
$
|
11,840
|
|
|
$
|
37,464
|
|
Natural gas
derivative cash settlements received
|
4,337
|
|
|
992
|
|
|
12,316
|
|
|
27,041
|
|
Total commodity
derivative cash settlements
|
$
|
6,377
|
|
|
$
|
8,022
|
|
|
$
|
24,156
|
|
|
$
|
64,505
|
|
Production:
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
1,628
|
|
|
949
|
|
|
5,032
|
|
|
4,019
|
|
Natural gas liquids
(MGal)
|
10,617
|
|
|
9,111
|
|
|
38,159
|
|
|
36,757
|
|
Natural gas
(MMcf)
|
15,866
|
|
|
16,243
|
|
|
62,833
|
|
|
66,824
|
|
Total
(MBoe)
|
4,525
|
|
|
3,873
|
|
|
16,413
|
|
|
16,032
|
|
Average daily
production (Boe/d)
|
49,185
|
|
|
42,098
|
|
|
44,967
|
|
|
43,803
|
|
Average sales price
per unit (excluding commodity derivative cash
settlements):
|
|
|
|
|
Oil price (per
Bbl)
|
$
|
52.30
|
|
|
$
|
44.43
|
|
|
$
|
47.59
|
|
|
$
|
37.95
|
|
Natural gas liquids
price (per Gal)
|
$
|
0.76
|
|
|
$
|
0.61
|
|
|
$
|
0.65
|
|
|
$
|
0.42
|
|
Natural gas price
(per Mcf)(a)
|
$
|
2.76
|
|
|
$
|
2.70
|
|
|
$
|
2.74
|
|
|
$
|
2.19
|
|
Combined (per
Boe)
|
$
|
30.30
|
|
|
$
|
23.65
|
|
|
$
|
26.58
|
|
|
$
|
19.61
|
|
Average sales price
per unit (including commodity derivative cash
settlements):
|
|
|
|
|
Oil price (per
Bbl)
|
$
|
53.56
|
|
|
$
|
51.84
|
|
|
$
|
49.94
|
|
|
$
|
47.27
|
|
Natural gas liquids
price (per Gal)
|
$
|
0.76
|
|
|
$
|
0.61
|
|
|
$
|
0.65
|
|
|
$
|
0.42
|
|
Natural gas price
(per Mcf)(a)
|
$
|
3.04
|
|
|
$
|
2.76
|
|
|
$
|
2.93
|
|
|
$
|
2.60
|
|
Combined (per
Boe)
|
$
|
31.71
|
|
|
$
|
25.72
|
|
|
$
|
28.05
|
|
|
$
|
23.63
|
|
Average WTI oil spot
price (per Bbl)
|
$
|
55.27
|
|
|
$
|
49.14
|
|
|
$
|
50.80
|
|
|
$
|
43.29
|
|
Average Henry Hub
natural gas index price (per MMbtu)
|
$
|
2.91
|
|
|
$
|
3.04
|
|
|
$
|
2.99
|
|
|
$
|
2.52
|
|
Average unit costs
per Boe:
|
|
|
|
|
|
|
|
Production costs,
excluding production and other taxes
|
$
|
9.41
|
|
|
$
|
10.70
|
|
|
$
|
10.58
|
|
|
$
|
10.59
|
|
Ad valorem
taxes
|
$
|
0.56
|
|
|
$
|
0.04
|
|
|
$
|
0.59
|
|
|
$
|
0.60
|
|
Production and other
taxes
|
$
|
1.34
|
|
|
$
|
1.11
|
|
|
$
|
1.21
|
|
|
$
|
0.89
|
|
General and
administrative excluding transaction costs and LTIP
|
$
|
2.19
|
|
|
$
|
2.13
|
|
|
$
|
2.07
|
|
|
$
|
1.95
|
|
Total general and
administrative
|
$
|
4.47
|
|
|
$
|
3.61
|
|
|
$
|
3.01
|
|
|
$
|
2.72
|
|
Depletion,
depreciation, amortization and accretion
|
$
|
8.12
|
|
|
$
|
10.26
|
|
|
$
|
7.73
|
|
|
$
|
9.38
|
|
Annual Financial and Operating Results - 2017 Compared to
2016
- Production increased 3% to an annual record of 44,967 Boe/d in
2017 from 43,803 Boe/d in 2016 primarily due to increased oil
production from increased working interests as a result of the
Acceleration Payment and increased Permian Basin horizontal
development, partially offset by individually immaterial
divestitures and natural production declines.
- Average realized price, excluding net cash settlements from
commodity derivatives, increased 36% to $26.58 per Boe in 2017 from $19.61 per Boe in 2016. Average realized oil
price increased 25% to $47.59 in 2017
from $37.95 in 2016. This increase
was primarily driven by an increase in the average West Texas
Intermediate ("WTI") crude oil price of $7.51 per Bbl and improving realized regional
differentials. Average realized natural gas price increased 25% to
$2.74 per Mcf in 2017 from
$2.19 per Mcf in 2016. This increase
was primarily driven by an increase in the average Henry Hub
natural gas index price of $0.47 per
Mcf and increased natural gas volumes produced from assets in the
Permian Basin which are accounted for inclusive of the NGL content
contained within the natural gas volumes, resulting in a realized
gas price for those assets that is higher than the NYMEX Henry Hub
index price. Finally, our average realized NGL price increased 55%
to $0.65 per gallon in 2017 from
$0.42 per gallon in 2016.
- Production expenses, excluding ad valorem taxes, increased 2%
to $173.6 million in 2017 from
$169.8 million in 2016 primarily due
to increased workover and repair activity across all operating
regions, increased well count due to our Permian horizontal
drilling program and increased working interests as a result of the
Acceleration Payment, partially offset by general cost reduction
efforts. On an average cost per Boe basis, production expenses
decreased to $10.58 per Boe in 2017
from $10.59 per Boe in 2016, driven
primarily by increased low cost oil and NGL production.
- Non-cash impairment expense totaled $37.3 million in 2017 primarily driven by the
further decline in oil and natural gas futures prices in early 2017
as well as increased expenses and well performance during
2017.
- General and administrative expenses, excluding
transaction-related expenses and unit-based Long-Term Incentive
Plan ("LTIP") compensation expense increased to $34.0 million in 2017 compared to $31.2 million in 2016 due to general cost
increases.
- Cash settlements received on our commodity derivatives during
2017 were $24.2 million as compared
to $64.5 million in 2016. The
decrease was due to increased average commodity prices and lower
volumes under derivative contracts.
- Total development capital expenditures increased to
$176.8 million in 2017 from
$29.5 million in 2016 primarily due
to our increased exposure to our Permian horizontal development
under our JDA.
Financial and Operating Results - Fourth Quarter 2017
Compared to Fourth Quarter 2016
- Production increased 17% to 49,185 Boe/d from 42,098 Boe/d
primarily due to increased oil production from increased working
interests as a result of the Acceleration Payment and increased
Permian horizontal development, partially offset by individually
immaterial divestitures and natural production declines.
- Average realized price, excluding net cash settlements from
commodity derivatives, increased 28% to $30.30 per Boe in 2017 from $23.65 per Boe in 2016. Average realized oil
price increased 18% to $52.30 per Bbl
in 2017 from $44.43 per Bbl in 2016.
This increase of $7.87 was primarily
attributable to the increase in the average WTI crude oil price of
$6.13 and improving realized regional
differentials. Average realized natural gas prices increased 2% to
$2.76 per Mcf in 2017 from
$2.70 per Mcf in 2016. This increase
of $0.06 was primarily attributable
to increased natural gas volumes produced from assets in the
Permian Basin which are accounted for inclusive of the NGL content
contained within the natural gas volumes, resulting in a realized
gas price for those assets that is higher than the NYMEX Henry Hub
index price. This was partially offset by a decline in the average
Henry Hub gas price. Finally, our average realized NGL price
increased 25% to $0.76 per gallon in
2017 from $0.61 per gallon in
2016.
- Production expenses, excluding ad valorem taxes, increased 3%
to $42.6 million in 2017 from
$41.5 million in 2016. Production
expenses increased due to our Permian horizontal drilling program
and increased working interests as a result of the Acceleration
Payment partially offset by general cost reduction efforts. On a
per Boe basis, production expenses decreased to $9.41 from $10.70
or 12% driven primarily by increased low cost oil production.
- Non-cash impairment expense totaled $12.7 million in 2017 primarily driven by
declining natural gas futures prices, increased costs and well
performance.
- General and administrative expenses, excluding acquisition
costs and LTIP compensation expense, increased to $9.9 million in 2017 from $8.2 million in 2016 due to general cost
increases.
- Cash settlements received on our commodity derivatives were
$6.4 million during 2017 compared to
$8.0 million in 2016.
- Total development capital expenditures were $35.3 million in the fourth quarter of 2017.
Commodity Derivative Contracts
We enter into oil and natural gas derivative contracts to help
mitigate the risk of changing commodity prices. As of
February 21, 2018, we had entered into derivative agreements
to receive average NYMEX WTI crude oil prices and NYMEX Henry Hub
natural gas prices as summarized below:
WTI Crude Oil Swaps:
Calendar
Year
|
|
Volumes
(Bbls)
|
|
Average Price
per
Bbl
|
|
Price Range
per
Bbl
|
2018
|
|
2,998,500
|
|
|
$
|
54.67
|
|
|
$
|
51.20
|
|
-
|
$
|
63.68
|
|
WTI Crude Oil Costless Collars. As an illustrative example, 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
|
2018
|
|
1,551,250
|
|
$47.06
|
|
$60.29
|
Crude Oil Enhanced Swaps. As an illustrative example, 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
|
Calendar
Year
|
|
Volumes
(Bbls)
|
|
Price per
Bbl
|
|
Price per
Bbl
|
|
Price per
Bbl
|
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
|
2018
|
|
4,015,000
|
|
|
$
|
(1.13)
|
|
|
$
|
(1.25)
|
|
-
|
$
|
(0.80)
|
|
2019
|
|
730,000
|
|
|
$
|
(1.15)
|
|
|
$
|
(1.15)
|
|
Natural Gas Swaps (Henry Hub):
|
|
|
|
Average
|
|
Price Range
per
|
Calendar
Year
|
|
Volumes
(MMBtu)
|
|
Price per
MMBtu
|
|
MMBtu
|
2018
|
|
36,200,000
|
|
|
$
|
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.
Annual Report on Form 10-K
Our consolidated, audited financial statements and related
footnotes will be available in our annual 2017 Form 10-K which will
be filed on or about February 23, 2018.
Conference Call
As announced on February 8, 2018,
Legacy will host an investor conference call to discuss Legacy's
results and corresponding presentation materials on Thursday, February 22, 2018 at 9:00 a.m. (Central Time). Those wishing to
participate in the conference call should dial 877-870-4623. A
replay of the call will be available through Thursday, March 1, 2018, by dialing 877-344-7529
and entering replay code 10116400. Those wishing to listen to the
live or archived web cast via the Internet or view the
corresponding presentation materials 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
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, just like unitholders of
other master limited partnerships, are allocated taxable income
irrespective of cash distributions paid. Because Legacy's
unitholders are treated as partners that are allocated a share of
Legacy's taxable income irrespective of the amount of cash, if any,
distributed by Legacy, unitholders will be required to pay federal
income taxes and, in some cases, state and local income taxes on
their share of Legacy's taxable income, including its taxable
income associated with cancellation of debt ("COD income") or a
disposition of property by Legacy, even if they receive no cash
distributions from Legacy. As of January 21,
2016, Legacy has suspended all cash distributions to
unitholders and holders of the Preferred Units. Legacy may engage
in transactions to de-lever the Partnership and manage its
liquidity that may result in the allocation of income and gain to
its unitholders without a corresponding cash distribution. For
example, if Legacy sells assets and uses the proceeds to repay
existing debt or fund capital or operating expenditures, Legacy's
unitholders may be allocated taxable income and gain resulting from
the sale without receiving a cash distribution. Further, if Legacy
engages in debt exchanges, debt repurchases, or modifications of
its existing debt, these or similar transactions could result in
"cancellation of indebtedness" or COD income being allocated to
Legacy's unitholders as taxable income. For tax purposes, Legacy
repurchased $187 million of its
6.625% Senior Notes at $0.70 per
$1.00 principal amount on
December 31, 2017. Unitholders will
be allocated gain and income from asset sales and COD income and
may owe income tax as a result of such allocations notwithstanding
the fact that Legacy has suspended cash distributions to its
unitholders. The ultimate effect of any such allocations will
depend on the unitholder's individual tax position with respect to
its units. Unitholders are encouraged to consult their tax advisors
with respect to the consequences of potential transactions that may
result in income and gain to unitholders.
Additionally, if Legacy's unitholders, just like unitholders of
other master limited partnerships, sell any of their units, they
will recognize gain or loss equal to the difference between the
amount realized and their tax basis in those units. Prior
distributions to unitholders that in the aggregate exceeded the
cumulative net taxable income they were allocated for a unit
decreased the tax basis in that unit, and will, in effect, become
taxable income to Legacy's unitholders if the unit is sold at a
price greater than their tax basis in that unit, even if the price
received is less than original cost. A substantial portion of the
amount realized, whether or not representing gain, may be ordinary
income to Legacy's unitholders due to the potential recapture
items, including depreciation, depletion and intangible
drilling.
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
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December
31,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
(In thousands,
except per unit data)
|
Revenues:
|
|
|
|
|
|
|
|
Oil sales
|
$
|
85,150
|
|
|
$
|
42,164
|
|
|
$
|
239,448
|
|
|
$
|
152,507
|
|
Natural gas liquids
(NGL) sales
|
8,105
|
|
|
5,574
|
|
|
24,796
|
|
|
15,406
|
|
Natural gas
sales
|
43,837
|
|
|
43,853
|
|
|
172,057
|
|
|
146,444
|
|
Total
revenues
|
137,092
|
|
|
91,591
|
|
|
436,301
|
|
|
314,357
|
|
Expenses:
|
|
|
|
|
|
|
|
Oil and natural gas
production
|
45,121
|
|
|
41,628
|
|
|
183,219
|
|
|
179,333
|
|
Production and other
taxes
|
6,046
|
|
|
4,318
|
|
|
19,825
|
|
|
14,267
|
|
General and
administrative
|
20,216
|
|
|
13,981
|
|
|
49,372
|
|
|
43,639
|
|
Depletion,
depreciation, amortization and accretion
|
36,738
|
|
|
39,719
|
|
|
126,938
|
|
|
150,414
|
|
Impairment of
long-lived assets
|
12,735
|
|
|
41,731
|
|
|
37,283
|
|
|
61,796
|
|
(Gain) loss on
disposal of assets
|
(1,885)
|
|
|
(806)
|
|
|
1,606
|
|
|
(50,095)
|
|
Total
expenses
|
118,971
|
|
|
140,571
|
|
|
418,243
|
|
|
399,354
|
|
Operating income
(loss)
|
18,121
|
|
|
(48,980)
|
|
|
18,058
|
|
|
(84,997)
|
|
Other income
(expense):
|
|
|
|
|
|
|
|
Interest
income
|
20
|
|
|
13
|
|
|
64
|
|
|
67
|
|
Interest
expense
|
(24,838)
|
|
|
(16,502)
|
|
|
(89,206)
|
|
|
(79,060)
|
|
Gain on
extinguishment of debt
|
—
|
|
|
—
|
|
|
—
|
|
|
150,802
|
|
Equity in income of
equity method investees
|
5
|
|
|
7
|
|
|
17
|
|
|
—
|
|
Net gains (losses) on
commodity derivatives
|
(18,100)
|
|
|
(38,913)
|
|
|
17,776
|
|
|
(41,224)
|
|
Other
|
27
|
|
|
309
|
|
|
792
|
|
|
(179)
|
|
Loss before income
taxes
|
(24,765)
|
|
|
(104,066)
|
|
|
(52,499)
|
|
|
(54,591)
|
|
Income tax
expense
|
(561)
|
|
|
(519)
|
|
|
(1,398)
|
|
|
(1,229)
|
|
Net Loss
|
$
|
(25,326)
|
|
|
$
|
(104,585)
|
|
|
$
|
(53,897)
|
|
|
$
|
(55,820)
|
|
Distributions to
preferred unitholders
|
(4,750)
|
|
|
(5,542)
|
|
|
(19,000)
|
|
|
(19,000)
|
|
Net loss attributable
to unitholders
|
$
|
(30,076)
|
|
|
$
|
(110,127)
|
|
|
$
|
(72,897)
|
|
|
$
|
(74,820)
|
|
Loss per unit — basic
and diluted
|
$
|
(0.41)
|
|
|
$
|
(1.53)
|
|
|
$
|
(1.01)
|
|
|
$
|
(1.06)
|
|
Weighted average
number of units used in computing
loss per unit —
|
|
|
|
|
|
|
|
Basic and
diluted
|
72,595
|
|
|
72,056
|
|
|
72,405
|
|
|
70,605
|
|
LEGACY RESERVES
LP
|
CONDENSED
CONSOLIDATED BALANCE SHEETS
|
(UNAUDITED)
|
|
|
December
31,
|
|
2017
|
|
2016
|
|
(In
thousands)
|
ASSETS
|
Current
assets:
|
|
|
|
Cash
|
$
|
1,246
|
|
|
$
|
2,555
|
|
Accounts receivable,
net:
|
|
|
|
Oil and natural
gas
|
62,755
|
|
|
43,192
|
|
Joint interest
owners
|
27,420
|
|
|
23,414
|
|
Other
|
2
|
|
|
2
|
|
Fair value of
derivatives
|
13,424
|
|
|
6,162
|
|
Prepaid expenses and
other current assets
|
7,757
|
|
|
7,447
|
|
Total current
assets
|
112,604
|
|
|
82,772
|
|
Oil and natural gas
properties, at cost:
|
|
|
|
Proved oil and
natural gas properties using the successful efforts method of
accounting
|
3,529,971
|
|
|
3,305,856
|
|
Unproved
properties
|
28,023
|
|
|
13,448
|
|
Accumulated
depletion, depreciation, amortization and impairment
|
(2,204,638)
|
|
|
(2,137,395)
|
|
|
1,353,356
|
|
|
1,181,909
|
|
Other property and
equipment, net of accumulated depreciation and amortization of
$11,467 and $10,412, respectively
|
2,961
|
|
|
3,423
|
|
Operating rights, net
of amortization of $5,765 and $5,369, respectively
|
1,251
|
|
|
1,648
|
|
Fair value of
derivatives
|
14,099
|
|
|
20,553
|
|
Other
assets
|
8,811
|
|
|
9,521
|
|
Total
assets
|
$
|
1,493,082
|
|
|
$
|
1,299,826
|
|
|
LIABILITIES AND
PARTNERS' DEFICIT
|
Current
liabilities:
|
|
|
|
Accounts
payable
|
$
|
13,093
|
|
|
$
|
9,092
|
|
Accrued oil and
natural gas liabilities
|
81,318
|
|
|
53,248
|
|
Fair value of
derivatives
|
18,013
|
|
|
9,743
|
|
Asset retirement
obligation
|
3,214
|
|
|
2,980
|
|
Other
|
29,172
|
|
|
11,546
|
|
Total current
liabilities
|
144,810
|
|
|
86,609
|
|
Long-term
debt
|
1,346,769
|
|
|
1,161,394
|
|
Asset retirement
obligation
|
271,472
|
|
|
269,168
|
|
Fair value of
derivatives
|
1,075
|
|
|
4,091
|
|
Other long-term
liabilities
|
643
|
|
|
643
|
|
Total
liabilities
|
1,764,769
|
|
|
1,521,905
|
|
Commitments and
contingencies
|
|
|
|
Partners' equity
(deficit):
|
|
|
|
Series A Preferred
equity - 2,300,000 units issued and outstanding at December 31,
2017 and December 31, 2016
|
55,192
|
|
|
55,192
|
|
Series B Preferred
equity - 7,200,000 units issued and outstanding at December 31,
2017 and December 31, 2016
|
174,261
|
|
|
174,261
|
|
Incentive
distribution equity - 100,000 units issued and outstanding at
December 31, 2017 and December 31, 2016
|
30,814
|
|
|
30,814
|
|
Limited partners'
deficit - 72,594,620 and 72,056,097 units issued and outstanding at
December 31, 2017 and 2016, respectively
|
(531,794)
|
|
|
(482,200)
|
|
General
partner's deficit (approximately 0.03%)
|
(160)
|
|
|
(146)
|
|
Total
partners' deficit
|
(271,687)
|
|
|
(222,079)
|
|
Total liabilities and
partners' deficit
|
$
|
1,493,082
|
|
|
$
|
1,299,826
|
|
Non-GAAP Financial Measures
This press release, the financial tables and other supplemental
information include "Adjusted EBITDA" which 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. Consistent
with practices common to publicly traded partnerships, the board of
directors of our general partner historically has not varied the
distribution it declares based on such timing effects.
"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.
Adjusted EBITDA is defined as net income (loss) plus:
- Interest expense;
- (Gain) loss on extinguishment of debt;
- Income tax expense (benefit);
- Depletion, depreciation, amortization and accretion;
- Impairment of long-lived assets;
- (Gain) loss on sale of partnership investment;
- Loss (gain) on disposal of assets;
- Equity in (income) loss of equity method investees;
- Unit-based compensation expense (benefit) related to LTIP unit
awards accounted for under the equity or liability methods;
- Minimum payments received in excess of overriding royalty
interest earned;
- Equity in EBITDA of equity method investee;
- Net (gains) losses on commodity derivatives;
- Net cash settlements received (paid) on commodity derivatives;
and
- Transaction costs.
The following table presents a reconciliation of our
consolidated net income (loss) to Adjusted EBITDA:
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December
31,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
(In
thousands)
|
Net
loss
|
$
|
(25,326)
|
|
|
$
|
(104,585)
|
|
|
$
|
(53,897)
|
|
|
$
|
(55,820)
|
|
Plus:
|
|
|
|
|
|
|
|
Interest
expense
|
24,838
|
|
|
16,502
|
|
|
89,206
|
|
|
79,060
|
|
Gain on debt
extinguishment
|
—
|
|
|
—
|
|
|
—
|
|
|
(150,802)
|
|
Income tax
expense
|
561
|
|
|
519
|
|
|
1,398
|
|
|
1,229
|
|
Depletion,
depreciation, amortization and accretion
|
36,738
|
|
|
39,719
|
|
|
126,938
|
|
|
150,414
|
|
Impairment of
long-lived assets
|
12,735
|
|
|
41,731
|
|
|
37,283
|
|
|
61,796
|
|
(Gain) loss on
disposal of assets
|
(1,885)
|
|
|
(806)
|
|
|
1,606
|
|
|
(50,095)
|
|
Equity in income of
equity method investees
|
(5)
|
|
|
(7)
|
|
|
(17)
|
|
|
—
|
|
Unit-based
compensation expense
|
1,666
|
|
|
1,586
|
|
|
6,597
|
|
|
7,198
|
|
Minimum payments
received in excess of overriding royalty interest
earned(1)
|
509
|
|
|
434
|
|
|
1,936
|
|
|
1,659
|
|
Net (gains) losses on
commodity derivatives
|
18,100
|
|
|
38,913
|
|
|
(17,776)
|
|
|
41,224
|
|
Net cash settlements
received on commodity derivatives
|
6,377
|
|
|
8,022
|
|
|
24,156
|
|
|
64,505
|
|
Transaction
costs
|
8,631
|
|
|
4,158
|
|
|
8,769
|
|
|
5,245
|
|
Adjusted
EBITDA
|
$
|
82,939
|
|
|
$
|
46,186
|
|
|
$
|
226,199
|
|
|
$
|
155,613
|
|
|
|
(1)
|
Minimum payments
received in excess of overriding royalties earned under a
contractual agreement expiring December 31, 2019. The remaining
amount of the minimum payments are recognized in net
income.
|
CONTACT:
Legacy Reserves LP
Dan Westcott
Executive Vice President and Chief Financial Officer
432-689-5200
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SOURCE Legacy Reserves LP