MIDLAND, Texas, Aug. 1,
2018 /PRNewswire/ -- Legacy Reserves LP ("Legacy")
(NASDAQ:LGCY) today announced second quarter results for 2018
including the following highlights:
- Generated record quarterly oil production of 17,901 Bbls/d, a
4% increase relative to Q1'18;
- Commenced Wolfcamp drilling in Martin
County and began preparing surface locations ahead of a rig
move into Midland County;
- Brought 9 Permian horizontal wells online during the quarter,
bringing the total to 29 Permian horizontal wells brought online
year-to-date;
- Completed multiple strategic Permian acreage trades requiring
no net cash outlay which enhanced projected economics for 33 gross
drilling locations:
-
- Increased average lateral lengths for 3 of Legacy's core
Midland Basin tracts by 58%,
resulting in an increase in net lateral footage by 45,000
feet;
- Generated a net loss of $50.7
million;
- Generated Adjusted EBITDA of $72.1
million; and
- Subsequent to quarter-end, Legacy achieved meaningful progress
related to our previously announced Corporate Reorganization
including:
-
- Entered into a Stipulation and Agreement of Settlement (the
"Settlement Agreement") to settle the previously announced class
action lawsuit filed by holders of Preferred Units; and
- Now anticipate filing definitive proxy statement and commencing
unitholder solicitation in the coming days incorporating a special
meeting of unitholders to approve the Corporate Reorganization on
September 19, 2018 for unitholders of
record as of the close of business on July
26, 2018.
Paul T. Horne, Chairman of the
Board and Chief Executive Officer of Legacy's general partner,
commented, "I am really proud of the strong results reported by all
of our business units this quarter. Our business development and
land teams created significant potential value by completing
several complicated trades involving a puzzle of 11 tracts across
the Permian Basin and many counterparties. Our team fit those
pieces together in an optimized fashion that substantially improves
the projected economics of some of our core inventory. Our
operations team continues to find ways to improve leasehold
economics by leveraging our longstanding Permian position. We
remain committed to our lease-wide development approach, focused on
maximizing return on investment, production, reserves and cash flow
and we look forward to continuing this program as we transition to
a C-Corp."
Dan Westcott, President and Chief
Financial Officer of Legacy's general partner, commented, "Our team
continues to execute and we are glad to report oil production
growth that drives growth in EBITDA. While we have limited control
over the widening of our oil differentials that occurred this
quarter due to the widening of Mid-Cush basis, we are happy that we
have hedged most of that exposure in 2018 and a bit of it in 2019.
We gained good momentum in the field this quarter, and when
combined with our expanded Permian Basin footprint, we believe we
are well-positioned for success and are excited to realize Legacy's
transition to becoming a growth-oriented development company."
LEGACY RESERVES
LP
|
SELECTED FINANCIAL
AND OPERATING DATA
|
|
|
|
|
|
Three Months
Ended
June 30,
|
|
Six Months
Ended
June 30,
|
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
(In thousands,
except per unit data)
|
Revenues:
|
|
|
|
|
|
|
|
Oil sales
|
$
|
99,799
|
|
|
$
|
46,096
|
|
|
$
|
193,210
|
|
|
$
|
95,238
|
|
Natural gas liquids
(NGL) sales
|
5,735
|
|
|
4,921
|
|
|
13,131
|
|
|
9,971
|
|
Natural gas
sales
|
33,747
|
|
|
41,830
|
|
|
70,419
|
|
|
87,185
|
|
Total
revenue
|
$
|
139,281
|
|
|
$
|
92,847
|
|
|
$
|
276,760
|
|
|
$
|
192,394
|
|
Expenses:
|
|
|
|
|
|
|
|
Oil and natural gas
production, excluding ad valorem taxes
|
$
|
46,882
|
|
|
$
|
42,262
|
|
|
$
|
92,467
|
|
|
$
|
91,490
|
|
Ad valorem
taxes
|
2,549
|
|
|
2,540
|
|
|
4,931
|
|
|
4,529
|
|
Total oil and natural
gas production
|
$
|
49,431
|
|
|
$
|
44,802
|
|
|
$
|
97,398
|
|
|
$
|
96,019
|
|
Production and other
taxes
|
$
|
7,658
|
|
|
$
|
4,145
|
|
|
$
|
14,984
|
|
|
$
|
8,304
|
|
General and
administrative, excluding transaction costs and LTIP
|
$
|
8,003
|
|
|
$
|
7,046
|
|
|
$
|
17,505
|
|
|
$
|
15,669
|
|
Transaction
costs
|
1,607
|
|
|
52
|
|
|
3,389
|
|
|
84
|
|
LTIP
expense
|
12,886
|
|
|
1,483
|
|
|
25,692
|
|
|
3,380
|
|
Total general and
administrative
|
$
|
22,496
|
|
|
$
|
8,581
|
|
|
$
|
46,586
|
|
|
$
|
19,133
|
|
Depletion,
depreciation, amortization and accretion
|
$
|
38,139
|
|
|
$
|
27,689
|
|
|
$
|
74,686
|
|
|
$
|
56,485
|
|
Commodity derivative
cash settlements:
|
|
|
|
|
|
|
|
Oil derivative cash
settlements (paid) received
|
$
|
(6,309)
|
|
|
$
|
3,559
|
|
|
$
|
(11,203)
|
|
|
$
|
6,698
|
|
Natural gas
derivative cash settlements received
|
$
|
3,895
|
|
|
$
|
3,012
|
|
|
$
|
5,994
|
|
|
$
|
4,109
|
|
Production:
|
|
|
|
|
|
|
|
Oil
(MBbls)
|
1,629
|
|
|
1,044
|
|
|
3,176
|
|
|
2,081
|
|
Natural gas liquids
(MGal)
|
11,332
|
|
|
8,514
|
|
|
20,576
|
|
|
16,167
|
|
Natural gas
(MMcf)
|
14,555
|
|
|
15,604
|
|
|
28,835
|
|
|
31,196
|
|
Total
(MBoe)
|
4,325
|
|
|
3,847
|
|
|
8,472
|
|
|
7,665
|
|
Average daily
production (Boe/d)
|
47,527
|
|
|
42,275
|
|
|
46,807
|
|
|
42,348
|
|
Average sales price
per unit (excluding derivative cash settlements):
|
|
|
|
|
|
|
|
Oil price (per
Bbl)
|
$
|
61.26
|
|
|
$
|
44.15
|
|
|
$
|
60.83
|
|
|
$
|
45.77
|
|
Natural gas liquids
price (per Gal)
|
$
|
0.51
|
|
|
$
|
0.58
|
|
|
$
|
0.64
|
|
|
$
|
0.62
|
|
Natural gas price
(per Mcf)
|
$
|
2.32
|
|
|
$
|
2.68
|
|
|
$
|
2.44
|
|
|
$
|
2.79
|
|
Combined (per
Boe)
|
$
|
32.20
|
|
|
$
|
24.13
|
|
|
$
|
32.67
|
|
|
$
|
25.10
|
|
Average sales price
per unit (including derivative cash settlements):
|
|
|
|
|
|
|
|
Oil price (per
Bbl)
|
$
|
57.39
|
|
|
$
|
47.56
|
|
|
$
|
57.31
|
|
|
$
|
48.98
|
|
Natural gas liquids
price (per Gal)
|
$
|
0.51
|
|
|
$
|
0.58
|
|
|
$
|
0.64
|
|
|
$
|
0.62
|
|
Natural gas price
(per Mcf)
|
$
|
2.59
|
|
|
$
|
2.87
|
|
|
$
|
2.65
|
|
|
$
|
2.93
|
|
Combined (per
Boe)
|
$
|
31.65
|
|
|
$
|
25.84
|
|
|
$
|
32.05
|
|
|
$
|
26.51
|
|
Average WTI oil spot
price (per Bbl)
|
$
|
68.07
|
|
|
$
|
48.10
|
|
|
$
|
65.55
|
|
|
$
|
49.85
|
|
Average Henry Hub
natural gas index price (per MMbtu)
|
$
|
2.85
|
|
|
$
|
3.08
|
|
|
$
|
2.96
|
|
|
$
|
3.05
|
|
Average unit costs
per Boe:
|
|
|
|
|
|
|
|
Oil and natural gas
production, excluding ad valorem taxes
|
$
|
10.84
|
|
|
$
|
10.99
|
|
|
$
|
10.91
|
|
|
$
|
11.94
|
|
Ad valorem
taxes
|
$
|
0.59
|
|
|
$
|
0.66
|
|
|
$
|
0.58
|
|
|
$
|
0.59
|
|
Production and other
taxes
|
$
|
1.77
|
|
|
$
|
1.08
|
|
|
$
|
1.77
|
|
|
$
|
1.08
|
|
General and
administrative excluding transaction costs and LTIP
|
$
|
1.85
|
|
|
$
|
1.83
|
|
|
$
|
2.07
|
|
|
$
|
2.04
|
|
Total general and
administrative
|
$
|
5.20
|
|
|
$
|
2.23
|
|
|
$
|
5.50
|
|
|
$
|
2.50
|
|
Depletion,
depreciation, amortization and accretion
|
$
|
8.82
|
|
|
$
|
7.20
|
|
|
$
|
8.82
|
|
|
$
|
7.37
|
|
Financial and Operating Results - Three-Month Period Ended
June 30, 2018 Compared to Three-Month Period Ended
June 30, 2017
- Production increased 12% to 47,527 Boe/d from 42,275 Boe/d
primarily due to additional oil production from our Permian Basin
horizontal drilling operations and production attributable to the
additional working interests that reverted to us in connection with
making an acceleration payment on August 1,
2017 (the "Acceleration Payment") under our amended and
restated joint development agreement with TSSP. This was partially
offset by natural production declines and individually immaterial
divestitures completed in 2018 and 2017.
- Average realized price, excluding net cash settlements from
commodity derivatives, increased 33% to $32.20 per Boe in 2018 from $24.13 per Boe in 2017 driven by the significant
increase in oil prices and an increase in oil production as a
percentage of total production, partially offset by widening
regional differentials. Average realized oil price increased 39% to
$61.26 in 2018 from $44.15 in 2017 driven by an increase in the
average WTI crude oil price of $19.97
per Bbl, partially offset by the widening Mid-Cush differential.
Average realized natural gas price decreased 13% to $2.32 per Mcf in 2018 from $2.68 per Mcf in 2017. This decrease is primarily
the result of a decrease in NYMEX pricing, widening realized
regional differentials and our adoption of ASC 606. Finally, our
average realized NGL price decreased 12% to $0.51 per gallon in 2018 from $0.58 per gallon in 2017 due to increased volumes
with a higher percentage of lower-priced ethane.
- Production expenses, excluding ad valorem taxes, increased to
$46.9 million in 2018 from
$42.3 million in 2017, primarily due
to additional costs associated with increased production related to
our Permian horizontal drilling program as well as increased
working interests following the Acceleration Payment. On an average
cost per Boe basis, production expenses excluding ad valorem taxes
decreased 1% to $10.84 per Boe in
2018 from $10.99 per Boe in
2017.
- Non-cash impairment expense totaled $35.4 million driven by the decline in natural
gas futures prices.
- General and administrative expenses, excluding unit-based
Long-Term Incentive Plan ("LTIP") compensation expense, increased
to $9.6 million in 2018 from
$7.1 million in 2017 due to a
$1.5 million increase in transaction
costs and general cost increases. LTIP compensation expense
increased $11.4 million due to the
recent rise in our unit price.
- Cash settlements paid on our commodity derivatives during 2018
were $2.4 million compared to cash
receipts of $6.6 million in 2017. The
change in cash settlements is a result of higher commodity prices,
reduced nominal volumes hedged in Q2 2018 compared to Q2 2017 and
lower contracted hedge prices. This was partially offset by an
increase in cash receipts of our Mid-Cush derivatives.
- Total development capital expenditures increased to
$80.7 million in 2018 from
$24.6 million in 2017. The 2018
activity was comprised mainly of our Permian horizontal drilling
program.
Financial and Operating Results - Six-Month Period Ended
June 30, 2018 Compared to Six-Month Period Ended June 30,
2017
- Production increased 11% to 46,807 Boe/d from 42,348 Boe/d
primarily due to additional oil production from our Permian Basin
horizontal drilling operations and production attributable to the
additional working interests that reverted to us in connection with
the August 1, 2017 Acceleration
Payment. This was partially offset by natural production declines
and individually immaterial divestitures completed in 2018 and
2017.
- Average realized price, excluding net cash settlements from
commodity derivatives, increased 30% to $32.67 per Boe in 2018 from $25.10 per Boe in 2017 driven by the significant
increase in oil prices and an increase in oil production as a
percentage of total production, partially offset by widening
regional differentials. Average realized oil price increased 33% to
$60.83 in 2018 from $45.77 in 2017 driven by an increase in the
average WTI crude oil price of $15.70
per Bbl, partially offset by the widening Mid-Cush differential.
Average realized natural gas price decreased 13% to $2.44 per Mcf in 2018 from $2.79 per Mcf in 2017. This decrease is a result
of the decrease in the average Henry Hub natural gas index price of
approximately $0.09 per Mcf and
widening realized regional differentials. Finally, our average
realized NGL price increased 3% to $0.64 per gallon in 2018 from $0.62 per gallon in 2017 due to higher commodity
prices partially offset by increased volumes with a higher
percentage of lower-priced ethane.
- Our production expenses, excluding ad valorem taxes, increased
to $92.5 million in 2018 from
$91.5 million in 2017. This increase
was due to increased production related to our Permian horizontal
drilling program as well as increased working interests following
the Acceleration Payment, partially offset by cost containment
efforts. On an average cost per Boe basis, production expenses
decreased 9% to $10.91 per Boe in
2018 from $11.94 per Boe in
2017.
- Non-cash impairment expense totaled $35.4 million driven by the decline in natural
gas futures prices.
- General and administrative expenses, excluding unit-based LTIP
compensation expense totaled $20.9
million in 2018 compared to $15.8
million in 2017, reflecting a $3.3
million increase in transaction costs and general cost
increases. LTIP compensation expense increased $21.8 million due to the recent rise in our unit
price.
- Cash settlements paid on our commodity derivatives during 2018
were $5.2 million compared to cash
receipts of $10.8 million in 2017.
The change in cash settlements is a result of higher commodity
prices, reduced nominal volumes hedged in 2018 compared to 2017 and
lower contracted hedge prices. This was partially offset by an
increase in cash receipts of our Mid-Cush derivatives.
- Total development capital expenditures increased to
$140.4 million in 2018 from
$48.3 million in 2017. The 2018
activity was comprised mainly of our Permian horizontal drilling
program.
Commodity Derivative Contracts
We enter into oil and natural gas derivative contracts to help
mitigate the risk of changing commodity prices. As of July 31,
2018, we had entered into derivative agreements to receive average
prices as summarized below.
NYMEX WTI Crude Oil Swaps:
Time
Period
|
|
Volumes
(Bbls)
|
|
Average Price
per
Bbl
|
|
Price Range per
Bbl
|
July-December
2018
|
|
1,527,200
|
|
|
$54.76
|
|
$51.20
|
-
|
$63.68
|
2019
|
|
2,190,000
|
|
|
$58.88
|
|
$57.15
|
-
|
$61.20
|
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
|
July-December
2018
|
|
782,000
|
|
$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
|
July-December
2018
|
|
64,400
|
|
|
$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
|
July-December
2018
|
|
2,024,000
|
|
|
$(1.13)
|
|
$(1.25)
|
-
|
$(0.80)
|
2019
|
|
730,000
|
|
|
$(1.15)
|
|
$(1.15)
|
NYMEX Natural Gas Swaps (Henry Hub):
|
|
|
|
Average
|
|
Price Range
per
|
Time
Period
|
|
Volumes
(MMBtu)
|
|
Price per
MMBtu
|
|
MMBtu
|
July-December
2018
|
|
18,160,000
|
|
|
$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
August 7, 2018.
Credit Agreement Waiver
On July 31, 2018, the lenders for
our credit agreement agreed to waive our compliance with the ratio
of consolidated current assets to consolidated current liabilities
covenant contained in the credit agreement for the fiscal quarter
ended June 30, 2018.
Conference Call
As announced on July 18, 2018,
Legacy will host an investor conference call to discuss Legacy's
results on Thursday, August 2, 2018
at 9:00 a.m. (Central Time). Those
wishing to participate in the conference call should dial
877-870-4263. A replay of the call will be available through
Thursday, August 9, 2018, by dialing
877-344-7529 and entering replay code 10122434. Those wishing to
listen to the live or archived webcast via the Internet should go
to the Investor Relations tab of our website at www.LegacyLP.com.
Following our prepared remarks, we will be pleased to answer
questions from securities analysts and institutional portfolio
managers and analysts; the complete call is open to all other
interested parties on a listen-only basis.
About Legacy Reserves LP
Legacy Reserves LP is a master limited partnership headquartered
in Midland, Texas, focused on the
development of oil and natural gas properties primarily located in
the Permian Basin, East Texas,
Rocky Mountain and Mid-Continent regions of the United States. Additional information is
available at www.LegacyLP.com.
Additional Information for Holders of Legacy Units and Where
to Find It
Although Legacy has suspended distributions to both the 8%
Series A and Series B Fixed-to-Floating Rate Cumulative Redeemable
Perpetual Preferred Units (the "Preferred Units"), such
distributions continue to accrue. Pursuant to the terms of Legacy's
partnership agreement, Legacy is required to pay or set aside for
payment all accrued but unpaid distributions with respect to the
Preferred Units prior to or contemporaneously with making any
distribution with respect to Legacy's units. Accruals of
distributions on the Preferred Units are treated for tax purposes
as guaranteed payments for the use of capital that will generally
be taxable to the holders of such Preferred Units as ordinary
income even in the absence of contemporaneous distributions.
In addition, Legacy's unitholders, 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.
In connection with the proposed transaction that will transition
Legacy from an MLP to a C-Corp (the "Transaction"), Legacy Reserves
Inc. ("New Legacy") has filed with the U.S. Securities and Exchange
Commission (the "SEC") a registration statement on Form S-4,
which includes a preliminary proxy statement of Legacy and a
preliminary prospectus of New Legacy (the "proxy
statement/prospectus") which Legacy plans to mail to its
unitholders to solicit approval for the merger.
INVESTORS AND UNITHOLDERS ARE URGED TO READ THE PROXY
STATEMENT/PROSPECTUS AND OTHER RELEVANT DOCUMENTS FILED OR TO BE
FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY WHEN THEY BECOME
AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT
LEGACY AND NEW LEGACY, AS WELL AS THE TRANSACTION AND RELATED
MATTERS.
This press release does not constitute an offer to sell or the
solicitation of an offer to buy any securities or a solicitation of
any vote or approval, nor shall there be any sale of securities in
any jurisdiction in which such offer, solicitation or sale would be
unlawful prior to registration or qualification under the
securities laws of any such jurisdiction. No offering of securities
shall be made except by means of a prospectus meeting the
requirements of Section 10 of the U.S. Securities Act of 1933,
as amended.
A free copy of the proxy statement/prospectus and other filings
containing information about Legacy and New Legacy may be obtained
at the SEC's Internet site at www.sec.gov. In addition, the
documents filed with the SEC by Legacy and New Legacy may be
obtained free of charge by directing such request to: Legacy
Reserves LP, Attention: Investor Relations, at 303 W. Wall, Suite
1800, Midland, Texas 79701 or
emailing IR@legacylp.com or calling 855-534-5200. These
documents may also be obtained for free from Legacy's investor
relations website at
https://www.legacylp.com/investor-relations.
Legacy and its general partner's directors, executive officers,
other members of management and employees may be deemed to be
participants in the solicitation of proxies from Legacy's
unitholders in respect of the Transaction
described in the proxy statement/prospectus. Information
regarding the directors and executive officers of Legacy's general
partner is contained in Legacy's public filings with the SEC,
including its definitive proxy statement on Form DEF 14A filed with
the SEC on April 6, 2018.
A more complete description is
available in the registration statement and the proxy
statement/prospectus.
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 benefits of the Transaction to Legacy and its unitholders,
final court approval of the Settlement
Agreement, the anticipated completion of the Transaction or
the timing thereof, the expected future growth, dividends,
distributions of the reorganized 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 filings with
the SEC, 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
LP
|
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
|
(UNAUDITED)
|
|
|
|
|
|
Three Months
Ended
|
|
Six Months
Ended
|
|
June
30,
|
|
June
30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
(In thousands,
except per unit data)
|
Revenues:
|
|
|
|
|
|
|
|
Oil sales
|
$
|
99,799
|
|
|
$
|
46,096
|
|
|
$
|
193,210
|
|
|
$
|
95,238
|
|
Natural gas liquids
(NGL) sales
|
5,735
|
|
|
4,921
|
|
|
13,131
|
|
|
9,971
|
|
Natural gas
sales
|
33,747
|
|
|
41,830
|
|
|
70,419
|
|
|
87,185
|
|
Total
revenues
|
139,281
|
|
|
92,847
|
|
|
276,760
|
|
|
192,394
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
Oil and natural gas
production
|
49,431
|
|
|
44,802
|
|
|
97,398
|
|
|
96,019
|
|
Production and other
taxes
|
7,658
|
|
|
4,145
|
|
|
14,984
|
|
|
8,304
|
|
General and
administrative
|
22,496
|
|
|
8,581
|
|
|
46,586
|
|
|
19,133
|
|
Depletion,
depreciation, amortization and accretion
|
38,139
|
|
|
27,689
|
|
|
74,686
|
|
|
56,485
|
|
Impairment of
long-lived assets
|
35,381
|
|
|
1,821
|
|
|
35,381
|
|
|
9,883
|
|
(Gains) losses on
disposal of assets
|
(1,145)
|
|
|
11,049
|
|
|
(21,540)
|
|
|
5,525
|
|
Total
expenses
|
151,960
|
|
|
98,087
|
|
|
247,495
|
|
|
195,349
|
|
|
|
|
|
|
|
|
|
Operating (loss)
income
|
(12,679)
|
|
|
(5,240)
|
|
|
29,265
|
|
|
(2,955)
|
|
|
|
|
|
|
|
|
|
Other income
(expense):
|
|
|
|
|
|
|
|
Interest
income
|
3
|
|
|
8
|
|
|
15
|
|
|
9
|
|
Interest
expense
|
(28,589)
|
|
|
(20,614)
|
|
|
(55,957)
|
|
|
(40,747)
|
|
Gain on
extinguishment of debt
|
—
|
|
|
—
|
|
|
51,693
|
|
|
—
|
|
Equity in income of
equity method investees
|
3
|
|
|
1
|
|
|
20
|
|
|
12
|
|
Net gains (losses) on
commodity derivatives
|
(9,315)
|
|
|
14,516
|
|
|
(11,019)
|
|
|
49,185
|
|
Other
|
(2)
|
|
|
402
|
|
|
273
|
|
|
362
|
|
Income (loss) before
income taxes
|
(50,579)
|
|
|
(10,927)
|
|
|
14,290
|
|
|
5,866
|
|
Income tax
expense
|
(130)
|
|
|
(150)
|
|
|
(617)
|
|
|
(571)
|
|
Net income
(loss)
|
$
|
(50,709)
|
|
|
$
|
(11,077)
|
|
|
$
|
13,673
|
|
|
$
|
5,295
|
|
Distributions to
preferred unitholders
|
(4,750)
|
|
|
(4,750)
|
|
|
(9,500)
|
|
|
(9,500)
|
|
Net income (loss)
attributable to unitholders
|
$
|
(55,459)
|
|
|
$
|
(15,827)
|
|
|
$
|
4,173
|
|
|
$
|
(4,205)
|
|
|
|
|
|
|
|
|
|
Income (loss) per
unit - basic & diluted
|
$
|
(0.72)
|
|
|
$
|
(0.22)
|
|
|
$
|
0.05
|
|
|
$
|
(0.06)
|
|
Weighted average
number of units used in computing net income (loss) per unit
-
|
|
|
|
|
|
|
|
Basic
|
76,725
|
|
|
72,354
|
|
|
76,539
|
|
|
72,229
|
|
Diluted
|
76,725
|
|
|
72,354
|
|
|
77,433
|
|
|
72,229
|
|
LEGACY RESERVES
LP
|
CONDENSED
CONSOLIDATED BALANCE SHEETS
|
(UNAUDITED)
|
|
ASSETS
|
|
|
June 30,
2018
|
|
December 31,
2017
|
|
|
(In
thousands)
|
Current
assets:
|
|
|
|
|
Cash
|
|
$
|
5,948
|
|
|
$
|
1,246
|
|
Accounts receivable,
net:
|
|
|
|
|
Oil and natural
gas
|
|
57,676
|
|
|
62,755
|
|
Joint interest
owners
|
|
16,515
|
|
|
27,420
|
|
Other
|
|
6
|
|
|
2
|
|
Fair value of
derivatives
|
|
28,046
|
|
|
13,424
|
|
Prepaid expenses and
other current assets
|
|
10,457
|
|
|
7,757
|
|
Total current
assets
|
|
118,648
|
|
|
112,604
|
|
Oil and natural gas
properties using the successful efforts method, at cost:
|
|
|
|
|
Proved
properties
|
|
3,497,220
|
|
|
3,529,971
|
|
Unproved
properties
|
|
31,661
|
|
|
28,023
|
|
Accumulated
depletion, depreciation, amortization and impairment
|
|
(2,157,542)
|
|
|
(2,204,638)
|
|
|
|
1,371,339
|
|
|
1,353,356
|
|
Other property and
equipment, net of accumulated depreciation and amortization of
$11,971 and $11,467, respectively
|
|
2,532
|
|
|
2,961
|
|
Operating rights, net
of amortization of $5,944 and $5,765, respectively
|
|
1,072
|
|
|
1,251
|
|
Fair value of
derivatives
|
|
9,968
|
|
|
14,099
|
|
Other
assets
|
|
6,991
|
|
|
8,811
|
|
Total
assets
|
|
$
|
1,510,550
|
|
|
$
|
1,493,082
|
|
LIABILITIES AND
PARTNERS' DEFICIT
|
Current
liabilities:
|
|
|
|
|
Current debt,
net
|
|
$
|
505,222
|
|
|
$
|
—
|
|
Accounts
payable
|
|
6,626
|
|
|
13,093
|
|
Accrued oil and
natural gas liabilities
|
|
119,086
|
|
|
81,318
|
|
Fair value of
derivatives
|
|
27,740
|
|
|
18,013
|
|
Asset retirement
obligation
|
|
3,214
|
|
|
3,214
|
|
Other
|
|
46,538
|
|
|
29,172
|
|
Total current
liabilities
|
|
708,426
|
|
|
144,810
|
|
Long-term debt,
net
|
|
784,753
|
|
|
1,346,769
|
|
Asset retirement
obligation
|
|
261,031
|
|
|
271,472
|
|
Fair value of
derivatives
|
|
6,682
|
|
|
1,075
|
|
Other long-term
liabilities
|
|
643
|
|
|
643
|
|
Total
liabilities
|
|
1,761,535
|
|
|
1,764,769
|
|
Commitments and
contingencies
|
|
|
|
|
Partners'
deficit
|
|
|
|
|
Series A Preferred
equity - 2,300,000 units issued and outstanding at June 30, 2018
and December 31, 2017
|
|
55,192
|
|
|
55,192
|
|
Series B Preferred
equity - 7,200,000 units issued and outstanding at June 30, 2018
and December 31, 2017
|
|
174,261
|
|
|
174,261
|
|
Incentive
distribution equity - 100,000 units issued and outstanding at June
30, 2018 and December 31, 2017
|
|
30,814
|
|
|
30,814
|
|
Limited partners'
deficit - 76,793,940 and 72,594,620 units issued and outstanding at
June 30, 2018 and December 31, 2017, respectively
|
|
(511,095)
|
|
|
(531,794)
|
|
General partner's
deficit (approximately 0.02%)
|
|
(157)
|
|
|
(160)
|
|
Total partners'
deficit
|
|
(250,985)
|
|
|
(271,687)
|
|
Total liabilities and
partners' deficit
|
|
$
|
1,510,550
|
|
|
$
|
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 income (loss) to Adjusted EBITDA:
|
Three Months
Ended
|
|
Six Months
Ended
|
|
June
30,
|
|
June
30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
(In
thousands)
|
Net income
(loss)
|
$
|
(50,709)
|
|
|
$
|
(11,077)
|
|
|
$
|
13,673
|
|
|
$
|
5,295
|
|
Plus:
|
|
|
|
|
|
|
|
Interest
expense
|
28,589
|
|
|
20,614
|
|
|
55,957
|
|
|
40,747
|
|
Gain on
extinguishment of debt
|
—
|
|
|
—
|
|
|
(51,693)
|
|
|
—
|
|
Income tax
expense
|
130
|
|
|
150
|
|
|
617
|
|
|
571
|
|
Depletion,
depreciation, amortization and accretion
|
38,139
|
|
|
27,689
|
|
|
74,686
|
|
|
56,485
|
|
Impairment of
long-lived assets
|
35,381
|
|
|
1,821
|
|
|
35,381
|
|
|
9,883
|
|
(Gain) loss on
disposal of assets
|
(1,145)
|
|
|
11,049
|
|
|
(21,540)
|
|
|
5,525
|
|
Equity in income of
equity method investees
|
(3)
|
|
|
(1)
|
|
|
(20)
|
|
|
(12)
|
|
Unit-based
compensation expense
|
12,886
|
|
|
1,483
|
|
|
25,692
|
|
|
3,380
|
|
Minimum payments
received in excess of overriding royalty interest
earned(1)
|
334
|
|
|
470
|
|
|
856
|
|
|
915
|
|
Net (gains) losses on
commodity derivatives
|
9,315
|
|
|
(14,516)
|
|
|
11,019
|
|
|
(49,185)
|
|
Net cash settlements
(paid) received on commodity derivatives
|
(2,414)
|
|
|
6,571
|
|
|
(5,209)
|
|
|
10,807
|
|
Transaction
costs
|
1,607
|
|
|
52
|
|
|
3,389
|
|
|
84
|
|
Adjusted
EBITDA
|
$
|
72,110
|
|
|
$
|
44,305
|
|
|
$
|
142,808
|
|
|
$
|
84,495
|
|
|
|
(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.
|
CONTACT:
|
Legacy Reserves
LP
|
|
Dan
Westcott
|
|
President and Chief
Financial Officer
|
|
(432)
689-5200
|
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SOURCE Legacy Reserves LP