MIDLAND, Texas, March 18,
2019 /PRNewswire/ -- Legacy Reserves Inc. ("Legacy") (NASDAQ: LGCY)
today announced the 2018 fourth quarter and year-end results. These
results are subject to the completion of audited financial
statements to be filed within our forthcoming Form 10-K.
Highlights since the third quarter 2018 include:
- Generated quarterly oil production of 18,630 Bbls/d and record
annual oil production of 18,162 bbls/d which represents a 32%
year-over-year increase;
- Brought 7 Permian horizontal wells online late in the quarter,
including:
-
- One 4-well pad of 10,000' Wolfcamp B wells in Martin County, each of which achieved average
peak rates of nearly 1,100 bbls/d prior to installation of
artificial lift equipment; and
- Three 7,500'-8,000' wells in Lea
County in the 1st, 2nd and
3rd Bone Spring formations, which achieved average peak
rates of nearly 1,000 bbls/d;
- Drilled our first two horizontal Wolfcamp wells in Lea County with first production expected Q1
2019;
- Commenced drilling a 6-well pad in Northern Midland County consisting of 7,500'
laterals across four horizons;
- Completed three Permian land swaps, enhancing drilling
prospects and adding drilling locations in Lea County, NM and Martin and Midland Counties, TX:
-
- Increased net lateral footage by 62,000'; and
- Increased average lateral lengths 17% to approximately 7,500'
for the 106 gross drilling locations comprising the 4 affected
prospect areas;
- Completed 6 divestitures of 554 non-core, low-value wells
generating approximately $19 million
of proceeds;
- Extinguished $16.7 million of
debt through equity exchanges, including exchanges after year end,
at an average implied conversion price of $2.76 per share; and
- Generated net income of $78.0
million and Adjusted EBITDA of $55.7
million for the fourth quarter.
Dan Westcott, Legacy's Chief
Executive Officer, commented, "The team continues to execute on our
goals to efficiently develop our significant Permian horizontal
resource, high-grade our assets by divesting non-core properties,
and enhance our near-term drilling prospects by trading our small
tracts. We're proud of our recent well results in
Martin County and look forward to
executing in new areas across Midland and Howard Counties later this year. I am
proud of the Legacy team and their ability to post strong results
despite our challenged financial situation."
Robert Norris, Legacy's Chief
Financial Officer, commented, "Through 2018, Legacy completed a
corporate reorganization, improved our total leverage metrics,
participated in value-accretive acreage trades, and sold non-core
assets in an effort to improve our leverage profile and access to
capital markets. We continue that effort with our announced
$135 million 2019 capital budget,
which is a meaningful reduction in activity, designed to drill
within cash flow. We look forward to working with our stakeholders
and advisors to address our capital structure and determine the
best path forward for Legacy."
Proved Reserves
The following information represents estimates of our proved
reserves as of December 31, 2018 which have been prepared in
compliance with the SEC rules using an average WTI price, as posted
by Plains Marketing L.P., of $65.56
per Bbl for oil and an average natural gas price, as posted by
Platts Gas Daily, of $3.10 per
MMBtu.
Operating
Regions
|
|
Oil
(MBbls)
|
|
Natural Gas
(MMcf)
|
|
NGLs
(MBbls)
|
|
Total
(MBoe)
|
|
%
Liquids
|
|
%
PDP
|
|
%
Total
|
Permian
Basin
|
|
44,671
|
|
|
116,879
|
|
|
660
|
|
|
64,811
|
|
|
70
|
%
|
|
90
|
%
|
|
39
|
%
|
East Texas
|
|
103
|
|
|
292,249
|
|
|
211
|
|
|
49,022
|
|
|
1
|
%
|
|
100
|
%
|
|
30
|
%
|
Rocky
Mountain
|
|
6,479
|
|
|
206,541
|
|
|
7,257
|
|
|
48,160
|
|
|
29
|
%
|
|
100
|
%
|
|
29
|
%
|
Mid-Continent
|
|
824
|
|
|
6,051
|
|
|
1,083
|
|
|
2,916
|
|
|
65
|
%
|
|
92
|
%
|
|
2
|
%
|
Total
|
|
52,077
|
|
|
621,720
|
|
|
9,211
|
|
|
164,909
|
|
|
37
|
%
|
|
96
|
%
|
|
100
|
%
|
2019 Capital Program By Category
|
Gross
|
|
Net
|
|
Percent of
Net
|
|
(In
millions)
|
|
|
Horizontal Permian
development
|
$
|
227
|
|
|
$
|
122
|
|
|
90
|
%
|
Workovers and
recompletions
|
7
|
|
|
5
|
|
|
4
|
%
|
Facilities,
midstream, seismic & land
|
8
|
|
|
8
|
|
|
6
|
%
|
Total capital
expenditures
|
$
|
242
|
|
|
$
|
135
|
|
|
100
|
%
|
We serve as operator of more than 90% 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, credit conditions, or
otherwise.
Credit Agreement Update and Strategic Alternatives
Legacy continues to diligently work with the lenders under its
revolving credit facility (the "Facility") for the execution of a
maturity extension under the Facility.
As previously announced, Legacy is evaluating and exploring
potential strategic alternatives. These alternatives include, among
others, a sale or other business combination transaction, sales of
assets, financing transactions, or some combination of these.
Director Transition
In association with his promotion to Chief Executive Officer,
Dan Westcott, has been appointed to
the Board of Directors effective immediately. In an effort to
enhance the Company's governance practices, Cary Brown, a former Chief Executive Officer of
Legacy's predecessor entity, has elected to resign as a director of
the Board coincident with Mr. Westcott's appointment. Mr. Brown
stated, "Legacy has been a blessing in my life since its inception.
I pray for their success through this difficult backdrop and trust
the management team and Board will keep fighting for the Company's
best interests."
LEGACY RESERVES
INC.
|
SELECTED FINANCIAL
AND OPERATING DATA
|
(Unaudited)
|
|
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December 31,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
(In thousands,
except per unit data)
|
Revenues
|
|
|
|
|
|
|
|
Oil sales
|
$
|
83,455
|
|
|
$
|
85,150
|
|
|
$
|
375,444
|
|
|
$
|
239,448
|
|
Natural gas liquids
sales
|
6,848
|
|
|
8,105
|
|
|
27,750
|
|
|
24,796
|
|
Natural gas
sales
|
42,591
|
|
|
43,837
|
|
|
151,667
|
|
|
172,057
|
|
Total
revenues
|
$
|
132,894
|
|
|
$
|
137,092
|
|
|
$
|
554,861
|
|
|
$
|
436,301
|
|
Expenses:
|
|
|
|
|
|
|
|
Oil and natural gas
production
|
$
|
49,447
|
|
|
$
|
42,594
|
|
|
$
|
191,345
|
|
|
$
|
173,599
|
|
Ad valorem
taxes
|
2,136
|
|
|
2,527
|
|
|
8,940
|
|
|
9,620
|
|
Total
|
$
|
51,583
|
|
|
$
|
45,121
|
|
|
$
|
200,285
|
|
|
$
|
183,219
|
|
Production and other
taxes
|
$
|
6,827
|
|
|
$
|
6,046
|
|
|
$
|
29,532
|
|
|
$
|
19,825
|
|
General and
administrative excluding transaction costs and LTIP
|
$
|
11,684
|
|
|
$
|
9,919
|
|
|
$
|
39,041
|
|
|
$
|
34,006
|
|
Transaction
costs
|
795
|
|
|
8,631
|
|
|
5,635
|
|
|
8,769
|
|
LTIP
expense
|
(3,805)
|
|
|
1,666
|
|
|
28,362
|
|
|
6,597
|
|
Total general and
administrative
|
$
|
8,674
|
|
|
$
|
20,216
|
|
|
$
|
73,038
|
|
|
$
|
49,372
|
|
Depletion,
depreciation, amortization and accretion
|
$
|
45,724
|
|
|
$
|
36,738
|
|
|
$
|
159,998
|
|
|
$
|
126,938
|
|
Commodity derivative
cash settlements:
|
|
|
|
|
|
|
|
Oil derivative cash
settlements received
|
$
|
(3,940)
|
|
|
$
|
2,040
|
|
|
$
|
(16,845)
|
|
|
$
|
11,840
|
|
Natural gas
derivative cash settlements received
|
(3,782)
|
|
|
4,337
|
|
|
5,130
|
|
|
12,316
|
|
Total commodity
derivative cash settlements
|
$
|
(7,722)
|
|
|
$
|
6,377
|
|
|
$
|
(11,715)
|
|
|
$
|
24,156
|
|
Production:
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
1,714
|
|
|
1,628
|
|
|
6,629
|
|
|
5,032
|
|
Natural gas liquids
(MGal)
|
9,546
|
|
|
10,617
|
|
|
41,549
|
|
|
38,159
|
|
Natural gas
(MMcf)
|
14,596
|
|
|
15,866
|
|
|
58,457
|
|
|
62,833
|
|
Total
(MBoe)
|
4,374
|
|
|
4,525
|
|
|
17,361
|
|
|
16,413
|
|
Average daily
production (Boe/d)
|
47,543
|
|
|
49,185
|
|
|
47,564
|
|
|
44,967
|
|
Average sales price
per unit (excluding commodity derivative cash
settlements):
|
|
|
|
|
Oil price (per
Bbl)
|
$
|
48.69
|
|
|
$
|
52.30
|
|
|
$
|
56.64
|
|
|
$
|
47.59
|
|
Natural gas liquids
price (per Gal)
|
$
|
0.72
|
|
|
$
|
0.76
|
|
|
$
|
0.67
|
|
|
$
|
0.65
|
|
Natural gas price
(per Mcf)(a)
|
$
|
2.92
|
|
|
$
|
2.76
|
|
|
$
|
2.59
|
|
|
$
|
2.74
|
|
Combined (per
Boe)
|
$
|
30.38
|
|
|
$
|
30.30
|
|
|
$
|
31.96
|
|
|
$
|
26.58
|
|
Average sales price
per unit (including commodity derivative cash
settlements):
|
|
|
|
|
Oil price (per
Bbl)
|
$
|
46.39
|
|
|
$
|
53.56
|
|
|
$
|
54.10
|
|
|
$
|
49.94
|
|
Natural gas liquids
price (per Gal)
|
$
|
0.72
|
|
|
$
|
0.76
|
|
|
$
|
0.67
|
|
|
$
|
0.65
|
|
Natural gas price
(per Mcf)(a)
|
$
|
2.66
|
|
|
$
|
3.04
|
|
|
$
|
2.68
|
|
|
$
|
2.93
|
|
Combined (per
Boe)
|
$
|
28.62
|
|
|
$
|
31.71
|
|
|
$
|
31.29
|
|
|
$
|
28.05
|
|
Average WTI oil spot
price (per Bbl)
|
$
|
59.97
|
|
|
$
|
55.27
|
|
|
$
|
65.23
|
|
|
$
|
50.80
|
|
Average Henry Hub
natural gas index price (per MMbtu)
|
$
|
3.77
|
|
|
$
|
2.91
|
|
|
$
|
3.15
|
|
|
$
|
2.99
|
|
Average unit costs
per Boe:
|
|
|
|
|
|
|
|
Production costs,
excluding production and other taxes
|
$
|
11.30
|
|
|
$
|
9.41
|
|
|
$
|
11.02
|
|
|
$
|
10.58
|
|
Ad valorem
taxes
|
$
|
0.49
|
|
|
$
|
0.56
|
|
|
$
|
0.51
|
|
|
$
|
0.59
|
|
Production and other
taxes
|
$
|
1.56
|
|
|
$
|
1.34
|
|
|
$
|
1.70
|
|
|
$
|
1.21
|
|
General and
administrative excluding transaction costs and LTIP
|
$
|
2.67
|
|
|
$
|
2.19
|
|
|
$
|
2.25
|
|
|
$
|
2.07
|
|
Total general and
administrative
|
$
|
1.98
|
|
|
$
|
4.47
|
|
|
$
|
4.21
|
|
|
$
|
3.01
|
|
Depletion,
depreciation, amortization and accretion
|
$
|
10.45
|
|
|
$
|
8.12
|
|
|
$
|
9.22
|
|
|
$
|
7.73
|
|
Annual Financial and Operating Results - 2018 Compared to
2017
- Production increased 6% to an annual record of 47,564 Boe/d in
2018 from 44,967 Boe/d in 2017 primarily due to additional oil
production from our Permian Basin horizontal drilling operations
and higher realized ethane recoveries associated with our Piceance
assets for portions of 2018. 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 20% to $31.96 per Boe in 2018 from $26.58 per Boe in 2017. Average realized oil
price increased 19% to $56.64 in 2018
from $47.59 in 2017. This increase
was primarily driven by an increase in the average West Texas
Intermediate ("WTI") crude oil price of $14.43 per Bbl and partially offset by widening
realized regional differentials. Average realized natural gas price
decreased 5% to $2.59 per Mcf in 2018
from $2.74 per Mcf in 2017. This
decrease was primarily driven by widening realized regional
differentials partially offset by an increase in the average NYMEX
pricing. Finally, our average realized NGL price increased 3% to
$0.67 per gallon in 2018 from
$0.65 per gallon in 2017.
- Production expenses, excluding ad valorem taxes, increased 10%
to $191.3 million in 2018 from
$173.6 million in 2017 primarily due
to increased workover and repair activity across all operating
regions, increased well count due to our Permian horizontal
drilling program, partially offset by general cost reduction
efforts. On an average cost per Boe basis, production expenses
increased to $11.02 per Boe in 2018
from $10.58 per Boe in 2017, driven
primarily by increased well count, working interests, and general
cost inflations.
- Non-cash impairment expense totaled $68.0 million in 2018 primarily driven by the
further decline in oil and natural gas futures prices in early 2018
as well as increased expenses and well performance during
2018.
- General and administrative expenses, excluding
transaction-related expenses and unit-based Long-Term Incentive
Plan ("LTIP") compensation expense increased to $39.0 million in 2018 compared to $34.0 million in 2017 primarily due to reduced
overhead income which is recognized as a reduction in general and
administrative expenses. The reduction is related to dispositions
of oil and natural gas properties and as such, lower recovery
results in an increase in our expenses. The remaining increase was
due to general cost increases.
- Cash settlements paid on our commodity derivatives during 2018
were $11.7 million as compared to
cash receipts of $24.2 million in
2017. The decrease in cash settlements is a result of fluctuating
commodity prices and reduced nominal volumes hedged.
- Total development capital expenditures increased to
$229.5 million in 2018 from
$176.8 million in 2017. The 2018
activity was comprised mainly of the drilling and completion of
horizontal Permian wells.
Financial and Operating Results - Fourth Quarter 2018
Compared to Fourth Quarter 2017
- Production decreased 3% to 47,543 Boe/d from 49,185 Boe/d
primarily due to additional natural production declines in our
Piceance assets as well as immaterial asset sales. This was
partially offset by increased oil production from our Permian Basin
horizontal drilling program.
- Average realized price, excluding net cash settlements from
commodity derivatives, remained relatively flat at $30.38 per Boe in 2018 compared to $30.30 per Boe in 2017. Average realized oil
price decreased 7% to $48.69 per Bbl
in 2018 from $52.30 per Bbl in 2017.
This decrease of $3.61 was primarily
attributable to widening regional differentials as the average WTI
crude oil price increased by $4.70.
Average realized natural gas prices increased 6% to $2.92 per Mcf in 2018 from $2.76 per Mcf in 2017. This increase of
$0.16 was primarily attributable to
an increase in the average Henry Hub gas price. Finally, our
average realized NGL price decreased 5% to $0.72 per gallon in 2018 from $0.76 per gallon in 2017.
- Production expenses, excluding ad valorem taxes, increased 16%
to $49.4 million in 2018 from
$42.6 million in 2017. Production
expenses increased primarily due to increased workover and repair
activity across all operating regions and increased well count due
to our Permian horizontal drilling program, partially offset by
general cost reduction efforts. On a per Boe basis, production
expenses increased to $11.30 from
$9.41 or 20% driven primarily by
increased well work activities, decreased low cost oil production,
increased competition in the market place and general cost
inflations.
- Non-cash impairment expense totaled $13.6 million in 2018 primarily driven by the
write-off of unproved properties acquired since 2010 as well as
declining oil and natural gas futures prices, increased costs and
well performance.
- General and administrative expenses, excluding acquisition
costs and LTIP compensation expense, increased to $11.7 million in 2018 from $9.9 million in 2017 primarily due to reduced
overhead income which is recognized as a reduction in general and
administrative expenses. The reduction is related to dispositions
of oil and natural gas properties and as such, lower recovery
results in an increase in our expenses. The remaining increase was
due to general cost increases.
- Cash settlements paid on our commodity derivatives were
$7.7 million during 2018 compared to
receipts of $6.4 million in 2017. The
decrease in cash settlements is a result of fluctuating commodity
prices and reduced nominal volumes hedged.
- Total development capital expenditures were $58 million in the fourth quarter of 2018.
Commodity Derivative Contracts
The following tables summarize, for the periods indicated, our
oil and natural gas derivatives in place as of March 13, 2019
covering the period from January 1,
2019 through December 31,
2019. We use derivatives, including swaps, enhanced swaps
and three-way collars, as our mechanism for offsetting the cash
flow effects of changes in commodity prices whereby we pay the
counterparty floating prices and receive fixed prices from the
counterparty, which serves to reduce the effects on cash flow of
the floating prices we are paid by purchasers of our oil and
natural gas. These transactions are mostly settled based upon the
monthly average closing price of front-month NYMEX WTI oil and the
price on the last trading day of front-month NYMEX Henry Hub
natural gas.
Oil Swaps:
Calendar
Year
|
|
Volumes
(Bbls)
|
|
Average Price
per
Bbl
|
|
Price Range per
Bbl
|
2019
|
|
3,285,000
|
|
$61.33
|
|
$57.15
|
-
|
$67.65
|
Natural Gas Swaps:
|
|
|
|
Average
|
|
Price Range
per
|
Calendar
Year
|
|
Volumes
(MMBtu)
|
|
Price per
MMBtu
|
|
MMBtu
|
2019
|
|
37,175,000
|
|
$3.36
|
|
$3.05
|
-
|
$4.40
|
We have entered into regional crude oil differential swap
contracts in which we have swapped the floating WTI-ARGUS
(Midland) crude oil price for
floating WTI-ARGUS (Cushing) less
a fixed-price differential. As noted above, we receive a discount
to the NYMEX WTI crude oil price at the point of sale. Due to
refinery downtimes and limited takeaway capacity that has impacted
the Permian Basin, the difference between the WTI-ARGUS
(Midland) price, which is the
price we receive on almost all of our Permian crude oil production,
and the WTI-ARGUS (Cushing) price
reached historic highs in late 2012 and early 2013 and again in
late 2014. We entered into these differential swaps to negate a
portion of this volatility. The following table summarizes the oil
differential swap contracts currently in place as of March 13,
2019, covering the period from January 1,
2019 through December 31,
2019:
Calendar
Year
|
|
Volumes
(Bbls)
|
|
Average Price
per
Bbl
|
|
Price Range per
Bbl
|
2019
|
|
2,193,000
|
|
$(3.62)
|
|
$(5.60)
|
-
|
$(1.15)
|
We have entered into regional crude oil differential enhanced
swap contracts in which we have swapped the floating WTI-ARGUS
(Midland) crude oil price for
floating WTI-ARGUS (Cushing) crude
oil price less a fixed-price differential combined with a short
call option to enhance the price of the differential swap. The
following table summarizes the oil differential contracts currently
in place as of March 13, 2019, covering the period from
January 1, 2019 through December 31, 2019:
|
|
|
|
Average
Long
|
|
Average
Short
|
Calendar
Year
|
|
Volumes
(Bbls)
|
|
Put Price per
Bbl
|
|
Call Price per
Bbl
|
2019
|
|
1,460,000
|
|
$70.00
|
|
(2.91)
|
We have also entered into regional natural gas differential swap
contracts in which we have swapped the floating CIG natural gas
price for a floating NYMEX Henry Hub price less a fixed
differential. The following table summarizes these type of enhanced
swap contracts currently in place as of March 13, 2019,
covering the period from January 1,
2019 through December 31,
2019:
|
|
|
|
Average
|
|
Price Range
per
|
Calendar
Year
|
|
Volumes
(MMBtu)
|
|
Price per
MMBtu
|
|
MMBtu
|
2019
|
|
3,600,000
|
|
$(0.47)
|
|
$(0.46)
|
-
|
$(0.49)
|
About Legacy Reserves Inc.
Legacy Reserves Inc. is an independent energy company engaged in
the development, production and acquisition of oil and natural gas
properties in the United States.
Our 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, the evaluation of
financial, transactional, and other strategic alternatives,
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, the structure
and timing of any financial, transactional or other strategic
alternative and whether any such financial, transactional or other
strategic alternative will be completed; whether Legacy will be
able to receive an extension to the maturity of its revolving
credit facility; 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 Reserves 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 of 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. Our consolidated, audited
financial statements and related footnotes will be available in our
annual 2018 Form 10-K which is expected to be filed no later than
April 2, 2019.
LEGACY RESERVES
INC.
|
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
|
(UNAUDITED)
|
|
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December
31,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
(In thousands,
except per share data)
|
Revenues:
|
|
|
|
|
|
|
|
Oil sales
|
$
|
83,455
|
|
|
$
|
85,150
|
|
|
$
|
375,444
|
|
|
$
|
239,448
|
|
Natural gas liquids
(NGL) sales
|
6,848
|
|
|
8,105
|
|
|
27,750
|
|
|
24,796
|
|
Natural gas
sales
|
42,591
|
|
|
43,837
|
|
|
151,667
|
|
|
172,057
|
|
Total
revenues
|
132,894
|
|
|
137,092
|
|
|
554,861
|
|
|
436,301
|
|
Expenses:
|
|
|
|
|
|
|
|
Oil and natural gas
production
|
51,583
|
|
|
45,121
|
|
|
200,285
|
|
|
183,219
|
|
Production and other
taxes
|
6,827
|
|
|
6,046
|
|
|
29,532
|
|
|
19,825
|
|
General and
administrative
|
8,675
|
|
|
20,216
|
|
|
73,039
|
|
|
49,372
|
|
Depletion,
depreciation, amortization and accretion
|
45,724
|
|
|
36,738
|
|
|
159,998
|
|
|
126,938
|
|
Impairment of
long-lived assets
|
13,603
|
|
|
12,735
|
|
|
67,978
|
|
|
37,283
|
|
(Gain) loss on
disposal of assets
|
(9,631)
|
|
|
(1,885)
|
|
|
(23,803)
|
|
|
1,606
|
|
Total
expenses
|
116,781
|
|
|
118,971
|
|
|
507,029
|
|
|
418,243
|
|
Operating income
(loss)
|
16,113
|
|
|
18,121
|
|
|
47,832
|
|
|
18,058
|
|
Other income
(expense):
|
|
|
|
|
|
|
|
Interest
income
|
5
|
|
|
20
|
|
|
36
|
|
|
64
|
|
Interest
expense
|
(31,668)
|
|
|
(24,838)
|
|
|
(117,008)
|
|
|
(89,206)
|
|
Gain on
extinguishment of debt
|
2,266
|
|
|
—
|
|
|
66,066
|
|
|
—
|
|
Equity in income of
equity method investees
|
(9)
|
|
|
5
|
|
|
(19)
|
|
|
17
|
|
Net gains (losses) on
commodity derivatives
|
91,058
|
|
|
(18,100)
|
|
|
49,172
|
|
|
17,776
|
|
Other
|
99
|
|
|
27
|
|
|
722
|
|
|
792
|
|
Income (Loss) before
income taxes
|
77,864
|
|
|
(24,765)
|
|
|
46,801
|
|
|
(52,499)
|
|
Income tax
expense
|
148
|
|
|
(561)
|
|
|
(2,968)
|
|
|
(1,398)
|
|
Net Income
(Loss)
|
$
|
78,012
|
|
|
$
|
(25,326)
|
|
|
$
|
43,833
|
|
|
$
|
(53,897)
|
|
|
|
|
|
|
|
|
|
Income (Loss) per
share — basic and diluted
|
$
|
0.73
|
|
|
$
|
(0.25)
|
|
|
$
|
0.42
|
|
|
$
|
(0.54)
|
|
Weighted average
number of shares used in computing loss per share —
|
|
|
|
|
|
|
|
Basic and
diluted
|
107,319
|
|
|
100,239
|
|
|
105,087
|
|
|
100,049
|
|
LEGACY RESERVES
INC.
|
CONDENSED
CONSOLIDATED BALANCE SHEETS
|
(UNAUDITED)
|
|
|
December
31,
|
|
2018
|
|
2017
|
|
(In
thousands)
|
ASSETS
|
Current
assets:
|
|
|
|
Cash
|
$
|
1,098
|
|
|
$
|
1,246
|
|
Accounts receivable,
net:
|
|
|
|
Oil and natural
gas
|
56,615
|
|
|
62,755
|
|
Joint interest
owners
|
15,370
|
|
|
27,422
|
|
Other
|
—
|
|
|
—
|
|
Fair value of
derivatives
|
66,662
|
|
|
13,424
|
|
Prepaid expenses and
other current assets
|
11,347
|
|
|
7,757
|
|
Total current
assets
|
151,092
|
|
|
112,604
|
|
Oil and natural gas
properties, at cost:
|
|
|
|
Proved oil and
natural gas properties using the successful efforts method of
accounting
|
3,471,456
|
|
|
3,529,971
|
|
Unproved
properties
|
19,863
|
|
|
28,023
|
|
Accumulated
depletion, depreciation, amortization and impairment
|
(2,177,006)
|
|
|
(2,204,638)
|
|
|
1,314,313
|
|
|
1,353,356
|
|
Other property and
equipment, net of accumulated depreciation and amortization of
$12,323 and $11,467, respectively
|
2,456
|
|
|
2,961
|
|
Operating rights, net
of amortization of $6,123 and $5,765, respectively
|
894
|
|
|
1,251
|
|
Fair value of
derivatives
|
3,135
|
|
|
14,099
|
|
Other
assets
|
3,041
|
|
|
8,811
|
|
Total
assets
|
$
|
1,474,931
|
|
|
$
|
1,493,082
|
|
LIABILITIES AND
PARTNERS' DEFICIT
|
Current
liabilities:
|
|
|
|
Current
debt
|
$
|
540,365
|
|
|
$
|
—
|
|
Accounts
payable
|
11,227
|
|
|
13,093
|
|
Accrued oil and
natural gas liabilities
|
98,886
|
|
|
81,318
|
|
Fair value of
derivatives
|
—
|
|
|
18,013
|
|
Asset retirement
obligation
|
3,938
|
|
|
3,214
|
|
Other
|
13,953
|
|
|
29,172
|
|
Total current
liabilities
|
668,369
|
|
|
144,810
|
|
Long-term
debt
|
749,204
|
|
|
1,346,769
|
|
Asset retirement
obligation
|
248,796
|
|
|
271,472
|
|
Fair value of
derivatives
|
550
|
|
|
1,075
|
|
Other long-term
liabilities
|
643
|
|
|
643
|
|
Total
liabilities
|
1,667,562
|
|
|
1,764,769
|
|
Commitments and
contingencies
|
|
|
|
Stockholders'/Partners' equity (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, 109,442,278 shares
outstanding at December 31, 2018
|
1,094
|
|
|
—
|
|
Additional paid-in
capital
|
24,752
|
|
|
—
|
|
Accumulated
deficit
|
(218,477)
|
|
|
—
|
|
Total
stockholders'/partners' deficit
|
(192,631)
|
|
|
(271,687)
|
|
Total liabilities and
stockholders'/partners' deficit
|
$
|
1,474,931
|
|
|
$
|
1,493,082
|
|
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. Adjusted EBITDA may not be comparable to
similarly titled measures of other companies because all companies
may not calculate such measure 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.
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,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
(In
thousands)
|
Net income
(loss)
|
$
|
78,012
|
|
|
$
|
(25,326)
|
|
|
$
|
43,833
|
|
|
$
|
(53,897)
|
|
Plus:
|
|
|
|
|
|
|
|
Interest
expense
|
31,668
|
|
|
24,838
|
|
|
117,008
|
|
|
89,206
|
|
Gain on debt
extinguishment
|
(2,266)
|
|
|
—
|
|
|
(66,066)
|
|
|
—
|
|
Income tax
expense
|
(148)
|
|
|
561
|
|
|
2,968
|
|
|
1,398
|
|
Depletion,
depreciation, amortization and accretion
|
45,724
|
|
|
36,738
|
|
|
159,998
|
|
|
126,938
|
|
Impairment of
long-lived assets
|
13,603
|
|
|
12,735
|
|
|
67,978
|
|
|
37,283
|
|
(Gain) loss on
disposal of assets
|
(9,631)
|
|
|
(1,885)
|
|
|
(23,803)
|
|
|
1,606
|
|
Equity in income of
equity method investees
|
9
|
|
|
(5)
|
|
|
19
|
|
|
(17)
|
|
Unit-based
compensation expense
|
(3,805)
|
|
|
1,666
|
|
|
28,362
|
|
|
6,597
|
|
Minimum payments
received in excess of overriding royalty interest
earned(1)
|
529
|
|
|
509
|
|
|
1,902
|
|
|
1,936
|
|
Net (gains) losses on
commodity derivatives
|
(91,057)
|
|
|
18,100
|
|
|
(49,172)
|
|
|
(17,776)
|
|
Net cash settlements
received on commodity derivatives
|
(7,722)
|
|
|
6,377
|
|
|
(11,715)
|
|
|
24,156
|
|
Transaction
costs
|
796
|
|
|
8,631
|
|
|
5,635
|
|
|
8,769
|
|
Adjusted
EBITDA
|
$
|
55,712
|
|
|
$
|
82,939
|
|
|
$
|
276,947
|
|
|
$
|
226,199
|
|
|
|
(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
Inc.
|
|
Robert
Norris
|
|
Chief Financial
Officer
|
|
432-689-5200
|
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