Legacy Reserves LP ("Legacy") (NASDAQ:LGCY) today announced third
quarter results for 2017 including the following highlights:
- Completed $3.3 million of acreage acquisitions expanding our
future development opportunities including:
- 24 horizontal Spraberry and Wolfcamp drilling locations in the
Midland Basin, and
- 9 horizontal San Andres drilling locations on the Central Basin
Platform that leverage Legacy’s existing infrastructure and have
attractive offset development economics.
- Reduced commodity price risk by adding 5,300 Bbls/d of 2018 WTI
crude oil swaps at average swap price of $52.97 per barrel.
- Increased oil production to a record 14,380 Bbls/d, a 25%
increase relative to Q2 2017.
- Generated a net loss of $33.9 million.
- Generated Adjusted EBITDA of $58.8 million representing a 33%
increase compared to Q2 2017.
- Reduced lease operating expenses, excluding ad valorem taxes,
to $39.5 million representing a 6.5% decrease compared to Q2 2017
and yielding a record low LOE/BOE of $9.36.
- Extended the availability of the remaining $95 million undrawn
portion of the second lien term loan to October 25, 2018.
Paul T. Horne, Chairman of the Board, President
and Chief Executive Officer of Legacy's general partner commented,
“Our August 1st Acceleration Payment and revisions to our JDA
meaningfully increased our interest in our operated horizontal
Permian development program. We remain very pleased with the team’s
ability to efficiently develop this resource as we recently brought
on 9 additional wells. As always, we continue to optimize well
design and operational practices, and I’m proud of our vigilance
with costs as evidenced by our record-low LOE per Boe. Our land and
business development teams have once again enhanced our portfolio
through smart, cost-effective bolt-on acquisitions. We expect such
efforts will build long-term equity value as we identify and pursue
additional drilling prospects in our core operating areas.”
Dan Westcott, Executive Vice President and Chief
Financial Officer of Legacy’s general partner, commented, “During
the quarter, our high-density horizontal Permian development
schedule necessitated temporarily shutting in a
higher-than-anticipated amount of offset well production and,
consequently, our Q3 production fell short of expectations. We are
pleased with the results of these smart-minded, long-term focused
decisions to optimize asset value. Our revised 2017 financial
guidance implies 2H 2017 oil production growth of 41% relative to
1H 2017. While we are just beginning our 2018 capital budget
process, we currently anticipate spending development capital of
$200 to $225 million based on continuing a two-rig Permian program
under our JDA. The included preliminary 2018 financial guidance
shows 47% growth in oil production and 43% growth in Adjusted
EBITDA relative to 2017 estimates, to a midpoint of 20,100 Bbl/d
and $305 million, respectively. This significant growth underlines
our high-quality assets and operational strength. We continue to
focus on growing Adjusted EBITDA and asset value which should
meaningfully improve our credit metrics as the midpoint of our
preliminary 2018 guidance implies a free cash flow neutral program
that reduces total debt / pro forma Adjusted EBITDA
by about one and one-half times relative to year-end 2017
estimates. As part of our Fall redetermination, our borrowing base
was reduced $25 million to $575 million leaving us with current
availability of $89 million. In addition, we’re pleased to have
extended our $95 million of second lien availability for another
year, increasing our total liquidity and expanding our optionality
as we explore strategies to further delever the balance sheet and
position Legacy for long-term success.”
Financial Guidance
The following table sets forth certain
assumptions used by Legacy to estimate its anticipated results of
operations for 2017 and 2018. These estimates do not include any
future acquisitions of additional oil or natural gas properties. In
addition, these estimates are based on, among other things,
assumptions of capital expenditure levels, current indications of
supply and demand for oil and natural gas and current operating and
labor costs. The guidance set forth below does not constitute any
form of guarantee, assurance or promise that the matters indicated
will actually be achieved. The guidance below sets forth
management’s best estimate based on current and anticipated market
conditions and other factors. While we believe that these estimates
and assumptions are reasonable, they are inherently uncertain and
are subject to, among other things, significant business, economic,
regulatory, environmental and competitive risks and uncertainties
that could cause actual results to differ materially from those we
anticipate, as set forth under “Cautionary Statement Relevant to
Forward-Looking Information.”
|
Q4 2017E Range |
|
FY 2017E Range |
|
PreliminaryFY 2018E
Range |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands unless otherwise noted) |
Production: |
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls/d) |
17,100 |
|
- |
17,700 |
|
|
13,637 |
|
- |
13,789 |
|
|
18,800 |
|
- |
21,400 |
|
Natural gas liquids
(Bbls/d) |
2,275 |
|
- |
2,325 |
|
|
2,370 |
|
- |
2,383 |
|
|
2,025 |
|
- |
2,300 |
|
Natural gas
(MMcf/d) |
170.0 |
|
- |
174.0 |
|
|
171.5 |
|
- |
172.5 |
|
|
162.5 |
|
- |
177.5 |
|
Total (Boe/d) |
47,708 |
|
- |
49,025 |
|
|
44,590 |
|
- |
44,922 |
|
|
47,908 |
|
- |
53,283 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
expenses(1) |
$ |
43,300 |
|
- |
$ |
44,300 |
|
|
$ |
174,306 |
|
- |
$ |
175,306 |
|
|
$ |
170,000 |
|
- |
$ |
190,000 |
|
Capital
expenditures |
$ |
40,000 |
|
- |
$ |
42,000 |
|
|
$ |
181,476 |
|
- |
$ |
183,476 |
|
|
$ |
200,000 |
|
- |
$ |
225,000 |
|
Adjusted EBITDA(2) |
$ |
68,000 |
|
- |
$ |
71,000 |
|
|
$ |
211,259 |
|
- |
$ |
214,259 |
|
|
$ |
280,000 |
|
- |
$ |
330,000 |
|
(1) Excludes ad valorem and production taxes.(2) 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 10/1/2017
(2018 average oil $51.94 / $3.05 natural gas).
|
LEGACY RESERVES LP |
SELECTED FINANCIAL AND OPERATING
DATA |
|
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands, except per unit
data) |
Revenues: |
|
|
|
|
|
|
|
Oil
sales |
$ |
59,060 |
|
|
$ |
38,751 |
|
|
$ |
154,298 |
|
|
$ |
110,343 |
|
Natural
gas liquids (NGL) sales |
6,720 |
|
|
3,457 |
|
|
16,691 |
|
|
9,832 |
|
Natural
gas sales |
41,035 |
|
|
41,332 |
|
|
128,220 |
|
|
102,591 |
|
Total
revenue |
$ |
106,815 |
|
|
$ |
83,540 |
|
|
$ |
299,209 |
|
|
$ |
222,766 |
|
Expenses: |
|
|
|
|
|
|
|
Oil and
natural gas production, excluding ad valorem taxes |
$ |
39,515 |
|
|
$ |
40,118 |
|
|
$ |
131,005 |
|
|
$ |
128,299 |
|
Ad
valorem taxes |
2,564 |
|
|
3,003 |
|
|
7,093 |
|
|
9,406 |
|
Total oil
and natural gas production |
$ |
42,079 |
|
|
$ |
43,121 |
|
|
$ |
138,098 |
|
|
$ |
137,705 |
|
Production and other taxes |
$ |
5,475 |
|
|
$ |
3,986 |
|
|
$ |
13,779 |
|
|
$ |
9,949 |
|
General
and administrative, excluding trans. related costs and LTIP |
$ |
8,418 |
|
|
$ |
7,490 |
|
|
$ |
24,087 |
|
|
$ |
22,959 |
|
Transaction related costs |
54 |
|
|
296 |
|
|
138 |
|
|
1,087 |
|
LTIP
expense |
1,551 |
|
|
1,445 |
|
|
4,931 |
|
|
5,612 |
|
Total
general and administrative |
$ |
10,023 |
|
|
$ |
9,231 |
|
|
$ |
29,156 |
|
|
$ |
29,658 |
|
Depletion, depreciation, amortization and accretion |
$ |
33,715 |
|
|
$ |
36,068 |
|
|
$ |
90,200 |
|
|
$ |
110,695 |
|
Commodity derivative
cash settlements: |
|
|
|
|
|
|
|
Oil
derivative cash settlements received |
$ |
3,102 |
|
|
$ |
8,089 |
|
|
$ |
9,800 |
|
|
$ |
30,434 |
|
Natural
gas derivative cash settlements received |
$ |
3,870 |
|
|
$ |
3,524 |
|
|
$ |
7,979 |
|
|
$ |
26,049 |
|
Production: |
|
|
|
|
|
|
|
Oil
(MBbls) |
1,323 |
|
|
962 |
|
|
3,404 |
|
|
3,070 |
|
Natural
gas liquids (MGal) |
11,375 |
|
|
9,742 |
|
|
27,542 |
|
|
27,646 |
|
Natural
gas (MMcf) |
15,771 |
|
|
16,572 |
|
|
46,967 |
|
|
50,581 |
|
Total
(MBoe) |
4,222 |
|
|
3,956 |
|
|
11,888 |
|
|
12,158 |
|
Average
daily production (Boe/d) |
45,891 |
|
|
43,000 |
|
|
43,546 |
|
|
44,372 |
|
Average sales price per
unit (excluding derivative cash settlements): |
|
|
|
|
|
|
|
Oil price
(per Bbl) |
$ |
44.64 |
|
|
$ |
40.28 |
|
|
$ |
45.33 |
|
|
$ |
35.94 |
|
Natural
gas liquids price (per Gal) |
$ |
0.59 |
|
|
$ |
0.35 |
|
|
$ |
0.61 |
|
|
$ |
0.36 |
|
Natural
gas price (per Mcf) |
$ |
2.60 |
|
|
$ |
2.49 |
|
|
$ |
2.73 |
|
|
$ |
2.03 |
|
Combined
(per Boe) |
$ |
25.30 |
|
|
$ |
21.12 |
|
|
$ |
25.17 |
|
|
$ |
18.32 |
|
Average sales price per
unit (including derivative cash settlements): |
|
|
|
|
|
|
|
Oil price
(per Bbl) |
$ |
46.99 |
|
|
$ |
48.69 |
|
|
$ |
48.21 |
|
|
$ |
45.86 |
|
Natural
gas liquids price (per Gal) |
$ |
0.59 |
|
|
$ |
0.35 |
|
|
$ |
0.61 |
|
|
$ |
0.36 |
|
Natural
gas price (per Mcf) |
$ |
2.85 |
|
|
$ |
2.71 |
|
|
$ |
2.90 |
|
|
$ |
2.54 |
|
Combined
(per Boe) |
$ |
26.95 |
|
|
$ |
24.05 |
|
|
$ |
26.66 |
|
|
$ |
22.97 |
|
Average WTI oil spot
price (per Bbl) |
$ |
48.18 |
|
|
$ |
44.85 |
|
|
$ |
49.30 |
|
|
$ |
41.35 |
|
Average Henry Hub
natural gas index price (per MMbtu) |
$ |
2.95 |
|
|
$ |
2.88 |
|
|
$ |
3.01 |
|
|
$ |
2.34 |
|
Average unit costs per
Boe: |
|
|
|
|
|
|
|
Oil and
natural gas production, excluding ad valorem taxes |
$ |
9.36 |
|
|
$ |
10.14 |
|
|
$ |
11.02 |
|
|
$ |
10.55 |
|
Ad
valorem taxes |
$ |
0.61 |
|
|
$ |
0.76 |
|
|
$ |
0.60 |
|
|
$ |
0.77 |
|
Production and other taxes |
$ |
1.30 |
|
|
$ |
1.01 |
|
|
$ |
1.16 |
|
|
$ |
0.82 |
|
General
and administrative excluding trans. related costs and LTIP |
$ |
1.99 |
|
|
$ |
1.89 |
|
|
$ |
2.03 |
|
|
$ |
1.89 |
|
Total
general and administrative |
$ |
2.37 |
|
|
$ |
2.33 |
|
|
$ |
2.45 |
|
|
$ |
2.44 |
|
Depletion, depreciation, amortization and accretion |
$ |
7.99 |
|
|
$ |
9.12 |
|
|
$ |
7.59 |
|
|
$ |
9.10 |
|
Financial and Operating Results - Three-Month Period
Ended September 30, 2017 Compared to Three-Month Period Ended
September 30, 2016
- Production increased 7% to 45,891 Boe/d from 43,000 Boe/d
primarily due to additional oil production from our drilling
operations in Howard County, Texas and Lea County, New Mexico and
production attributable to the additional working interests that
reverted to us in connection with making an acceleration payment
(the "Acceleration Payment") under our amended and restated joint
development agreement with TSSP (the "JDA"). This was partially
offset by natural production declines and individually immaterial
divestitures completed in 2016 and 2017.
- Average realized price, excluding net cash settlements from
commodity derivatives, increased 20% to $25.30 per Boe in 2017 from
$21.12 per Boe in 2016 driven by the significant increase in
commodity prices and increase in oil production as a percentage of
total production. Average realized oil price increased 11% to
$44.64 in 2017 from $40.28 in 2016 driven by an increase in the
average WTI crude oil price of $3.33 per Bbl and improving regional
differentials. Average realized natural gas price increased 4% to
$2.60 per Mcf in 2017 from $2.49 per Mcf in 2016. This increase is
primarily a result of the increase in average Henry Hub natural gas
index price of $0.07 per Mcf and improved realized regional
differentials. Finally, our average realized NGL price increased
69% to $0.59 per gallon in 2017 from $0.35 per gallon in 2016.
- Production expenses, excluding ad valorem taxes, decreased to
$39.5 million in 2017 from $40.1 million in 2016, primarily due to
cost containment efforts across all operating regions partially
offset by increased well count related to our Permian horizontal
drilling program and expenses associated with the additional
working interests that reverted to us in connection with making the
Acceleration Payment. On an average cost per Boe basis, production
expenses excluding ad valorem taxes decreased 8% to $9.36 per Boe
in 2017 from $10.14 per Boe in 2016.
- Non-cash impairment expense of $14.7 million in 2017 was driven
by the decrease in natural gas futures prices. Impairment expense
of $4.6 million in 2016 was driven by well performance and the
further decline in oil and natural gas prices during the
period.
- General and administrative expenses, excluding unit-based
Long-Term Incentive Plan ("LTIP") compensation expense, increased
to $8.5 million in 2017 from $7.8 million in 2016 due to general
cost increases.
- Cash settlements received on our commodity derivatives during
2017 were $7.0 million compared to $11.6 million in 2016. The
decline in cash settlements received is a result of the combination
of higher commodity prices and reduced nominal volumes hedges in Q3
2017 compared to Q3 2016 as well as lower contracted hedge
prices.
- Total development capital expenditures increased to $93.2
million in 2017 from $6.9 million in 2016. The 2017 activity was
comprised mainly of the drilling and completion of JDA wells. After
the Acceleration Payment, we became responsible for 85% of the
parties' combined interests of all remaining Tranche 1 capital
costs to be paid regardless of when such costs were incurred,
resulting in a larger increase in capital expenditures.
Financial and Operating Results - Nine-Month Period
Ended September 30, 2017 Compared to Nine-Month Period Ended
September 30, 2016
- Production decreased 2% to 43,546 Boe/d from 44,372 Boe/d
primarily due to natural production declines and individually
immaterial divestitures partially offset by growth from our
development activity and additional working interests that reverted
to us in connection with making the Acceleration Payment.
- Average realized price, excluding net cash settlements from
commodity derivatives, increased 37% to $25.17 per Boe in 2017 from
$18.32 per Boe in 2016 driven primarily by the significant increase
in commodity prices. Average realized oil price increased 26% to
$45.33 in 2017 from $35.94 in 2016 driven by an increase in the
average WTI crude oil price of $7.95 per Bbl. Average realized
natural gas price increased 35% to $2.73 per Mcf in 2017 from $2.03
per Mcf in 2016. This increase is a result of the increase in the
average Henry Hub natural gas index price of approximately $0.67
per Mcf partially offset by worsening realized regional
differentials. Finally, our average realized NGL price increased
70% to $0.61 per gallon in 2017 from $0.36 per gallon in 2016.
- Production expenses, excluding ad valorem taxes, increased 2%
to $131.0 million in 2017 from $128.3 million in 2016. On an
average cost per Boe basis, production expenses increased 4% to
$11.02 per Boe in 2017 from $10.55 per Boe in 2016. The increased
expenses were primarily due to higher workover and repair activity
in Q1 2017 across all operating regions and expenses associated
with the additional working interests that reverted to us in
connection with making the Acceleration Payment.
- Non-cash impairment expense totaled $24.5 million in 2017
driven by the continued decline in commodities futures prices and
increased expenses. Impairment expense totaled $20.1 million in
2016 due to well performance and the decline in commodities futures
prices in 2016.
- General and administrative expenses, excluding unit-based LTIP
compensation expense totaled $24.2 million in 2017 compared to
$24.0 million in 2016.
- Cash settlements received on our commodity derivatives during
2017 were $17.8 million compared to $56.5 million in 2016. The
decline in cash settlements received is a result of the combination
of reduced nominal volumes hedges in 2017 compared to 2016 as well
as lower average hedge prices and higher commodity prices.
- Total development capital expenditures increased to $141.5
million in 2017 from $18.5 million in 2016. The 2017 activity was
comprised mainly of the drilling and completion of JDA wells and
recompletions and workovers across all of our operating
regions.
Commodity Derivative Contracts
We enter into oil and natural gas derivative
contracts to help mitigate the risk of changing commodity prices.
As of October 30, 2017, we had entered into derivative
agreements to receive average NYMEX WTI crude oil prices and NYMEX
Henry Hub, NWPL, SoCal and San Juan natural gas prices as
summarized below.
WTI Crude Oil Swaps:
Time Period |
|
Volumes (Bbls) |
|
Average Price per Bbl |
|
Price Range per Bbl |
October-December
2017 |
|
46,000 |
|
|
$84.75 |
|
$84.75 |
2018 |
|
2,664,500 |
|
|
$53.54 |
|
$51.20 |
- |
$58.04 |
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 $45.00, $50.00
and $59.02, respectively for 2017 and $47.06, $50.00 and $60.29,
respectively for 2018.
|
|
|
|
Average Long |
|
Average Short |
Time Period |
|
Volumes (Bbls) |
|
Put Price per Bbl |
|
Call Price per Bbl |
October-December
2017 |
|
552,000 |
|
$45.00 |
|
$59.02 |
2018 |
|
1,551,250 |
|
$47.06 |
|
$60.29 |
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
$65.85, $65.85 and $73.85, respectively
for 2017 and $65.50, $65.50 and $73.50,
respectively for 2018.
|
|
|
|
Average Long Put |
|
Average Short Put |
|
Average Swap |
Time Period |
|
Volumes (Bbls) |
|
Price per Bbl |
|
Price per Bbl |
|
Price per Bbl |
October-December
2017 |
|
46,000 |
|
|
$57.00 |
|
$82.00 |
|
$90.85 |
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 |
October-December
2017 |
|
552,000 |
|
|
$(0.30) |
|
|
$(0.75) |
|
- |
$(0.05) |
|
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 |
Time Period |
|
Volumes (MMBtu) |
|
Price per MMBtu |
|
MMBtu |
October-December
2017 |
|
6,900,000 |
|
|
$3.36 |
|
$3.29 |
- |
$3.39 |
2018 |
|
36,200,000 |
|
|
$3.23 |
|
$3.04 |
- |
$3.39 |
2019 |
|
25,800,000 |
|
|
$3.36 |
|
$3.29 |
- |
$3.39 |
Natural Gas Costless Collars (Henry Hub). At an
annual Henry Hub price of $2.50, $3.00 and $3.50, the summary
position below would result in a net price of $2.90, $3.00 and
$3.44, respectively.
|
|
|
|
Average Long Put |
|
Average Short Call |
Time Period |
|
Volumes (MMBtu) |
|
Price per MMBtu |
|
Price per MMBtu |
October-December
2017 |
|
3,680,000 |
|
$2.90 |
|
$3.44 |
Natural Gas 3-Way Collars (Henry Hub). At an
annual average Henry Hub market price of $2.50, $3.00 and
$3.50, the summary position below would result in a net price of
$3.00, $3.50 and $4.00, respectively for 2017.
|
|
Volumes |
|
Average Short Put |
|
Average Long Put |
|
Average Short Call |
Time Period |
|
(MMBtu) |
|
Price per MMBtu |
|
Price per MMBtu |
|
Price per MMBtu |
October-December
2017 |
|
1,260,000 |
|
$3.75 |
|
$4.25 |
|
$5.53 |
Natural Gas Basis Swaps (NWPL, SoCal and San Juan):
|
|
October-December 2017 |
|
|
|
|
Average |
|
|
Volumes (MMBtu) |
|
Price per MMBtu |
NWPL |
|
1,840,000 |
|
$(0.16) |
SoCal |
|
630,200 |
|
$0.11 |
San Juan |
|
630,200 |
|
$(0.10) |
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 November 1, 2017.
Conference Call
As announced on October 18, 2017, Legacy will
host an investor conference call to discuss Legacy's results on
Thursday, November 2, 2017 at 9:00 a.m. (Central Time). Those
wishing to participate in the conference call should dial
877-266-0479. A replay of the call will be available through
Thursday, November 9, 2017, by dialing 855-859-2056 or 404-537-3406
and entering replay code 99408146. 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
acquisition and 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, during the
year ended December 31, 2016, Legacy closed 26 divestitures
generating net proceeds of $97.4 million, and Legacy may sell
additional assets and use the proceeds to repay existing debt or
fund capital expenditures, in which case Legacy’s unitholders may
be allocated taxable income and gain resulting from the sale, all
or a portion of which may be subject to recapture rules and taxed
as ordinary income rather than capital gain, without receiving a
cash distribution. Further, Legacy may pursue other opportunities
to reduce its existing debt, such as debt exchanges, debt
repurchases, or modifications that would result in COD income being
allocated to its unitholders as ordinary taxable income. The
ultimate effect of any income allocations will depend on the
unitholder's individual tax position with respect to that holder's
units, including the availability of any current or suspended
passive losses that may offset some portion of the COD income
allocable to a unitholder. 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 |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
|
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands, except per unit
data) |
Revenues: |
|
|
|
|
|
|
|
|
Oil
sales |
|
$ |
59,060 |
|
|
$ |
38,751 |
|
|
$ |
154,298 |
|
|
$ |
110,343 |
|
Natural
gas liquids (NGL) sales |
|
6,720 |
|
|
3,457 |
|
|
16,691 |
|
|
9,832 |
|
Natural
gas sales |
|
41,035 |
|
|
41,332 |
|
|
128,220 |
|
|
102,591 |
|
Total
revenues |
|
106,815 |
|
|
83,540 |
|
|
299,209 |
|
|
222,766 |
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
Oil and
natural gas production |
|
42,079 |
|
|
43,121 |
|
|
138,098 |
|
|
137,705 |
|
Production and other taxes |
|
5,475 |
|
|
3,986 |
|
|
13,779 |
|
|
9,949 |
|
General
and administrative |
|
10,023 |
|
|
9,231 |
|
|
29,156 |
|
|
29,658 |
|
Depletion, depreciation, amortization and accretion |
|
33,715 |
|
|
36,068 |
|
|
90,200 |
|
|
110,695 |
|
Impairment of long-lived assets |
|
14,665 |
|
|
4,618 |
|
|
24,548 |
|
|
20,065 |
|
(Gain)
loss on disposal of assets |
|
(2,034 |
) |
|
(8,447 |
) |
|
3,491 |
|
|
(49,289 |
) |
Total
expenses |
|
103,923 |
|
|
88,577 |
|
|
299,272 |
|
|
258,783 |
|
|
|
|
|
|
|
|
|
|
Operating
income (loss) |
|
2,892 |
|
|
(5,037 |
) |
|
(63 |
) |
|
(36,017 |
) |
|
|
|
|
|
|
|
|
|
Other income
(expense): |
|
|
|
|
|
|
|
|
Interest
income |
|
35 |
|
|
— |
|
|
44 |
|
|
54 |
|
Interest
expense |
|
(23,621 |
) |
|
(17,080 |
) |
|
(64,368 |
) |
|
(62,558 |
) |
Gain on
extinguishment of debt |
|
— |
|
|
— |
|
|
— |
|
|
150,802 |
|
Equity in
income (loss) of equity method investees |
|
— |
|
|
7 |
|
|
12 |
|
|
(7 |
) |
Net gains
(losses) on commodity derivatives |
|
(13,309 |
) |
|
18,326 |
|
|
35,876 |
|
|
(2,311 |
) |
Other |
|
403 |
|
|
(296 |
) |
|
765 |
|
|
(487 |
) |
Income
(loss) before income taxes |
|
(33,600 |
) |
|
(4,080 |
) |
|
(27,734 |
) |
|
49,476 |
|
Income tax expense |
|
(266 |
) |
|
(223 |
) |
|
(837 |
) |
|
(710 |
) |
Net
income (loss) |
|
$ |
(33,866 |
) |
|
$ |
(4,303 |
) |
|
$ |
(28,571 |
) |
|
$ |
48,766 |
|
Distributions to Preferred unitholders |
|
(4,750 |
) |
|
(4,750 |
) |
|
(14,250 |
) |
|
(13,458 |
) |
Net
income (loss) attributable to unitholders |
|
$ |
(38,616 |
) |
|
$ |
(9,053 |
) |
|
$ |
(42,821 |
) |
|
$ |
35,308 |
|
|
|
|
|
|
|
|
|
|
Income
(loss) per unit - basic and diluted |
|
$ |
(0.53 |
) |
|
$ |
(0.13 |
) |
|
$ |
(0.59 |
) |
|
$ |
0.50 |
|
Weighted
average number of units used in computing net income (loss) per
unit - |
|
|
|
|
|
|
|
|
Basic and
diluted |
|
72,562 |
|
|
72,056 |
|
|
72,341 |
|
|
70,370 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LEGACY RESERVES LP |
CONDENSED CONSOLIDATED BALANCE
SHEETS |
(UNAUDITED) |
|
ASSETS |
|
|
September 30, 2017 |
|
December 31, 2016 |
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Current assets: |
|
|
|
|
Cash and
cash equivalents |
|
$ |
7,548 |
|
|
$ |
2,555 |
|
Accounts
receivable, net: |
|
|
|
|
Oil and
natural gas |
|
46,695 |
|
|
43,192 |
|
Joint
interest owners |
|
19,457 |
|
|
23,414 |
|
Other |
|
— |
|
|
2 |
|
Fair
value of derivatives |
|
15,566 |
|
|
6,162 |
|
Prepaid
expenses and other current assets |
|
8,425 |
|
|
7,447 |
|
Total
current assets |
|
97,691 |
|
|
82,772 |
|
Oil and natural gas
properties using the successful efforts method, at cost: |
|
|
|
|
Proved
properties |
|
3,495,569 |
|
|
3,305,856 |
|
Unproved
properties |
|
25,463 |
|
|
13,448 |
|
Accumulated depletion, depreciation, amortization and
impairment |
|
(2,159,559 |
) |
|
(2,137,395 |
) |
|
|
1,361,473 |
|
|
1,181,909 |
|
Other property and
equipment, net of accumulated depreciation and amortization of
$11,174 and $10,412, respectively |
|
3,142 |
|
|
3,423 |
|
Operating rights, net
of amortization of $5,666 and $5,369, respectively |
|
1,350 |
|
|
1,648 |
|
Fair value of
derivatives |
|
16,972 |
|
|
20,553 |
|
Other assets |
|
8,704 |
|
|
8,874 |
|
Investments in equity
method investees |
|
658 |
|
|
647 |
|
Total assets |
|
$ |
1,489,990 |
|
|
$ |
1,299,826 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS' DEFICIT |
Current
liabilities: |
|
|
|
|
Accounts
payable |
|
$ |
5,611 |
|
|
$ |
9,092 |
|
Accrued
oil and natural gas liabilities |
|
98,104 |
|
|
53,248 |
|
Fair
value of derivatives |
|
646 |
|
|
9,743 |
|
Asset
retirement obligation |
|
2,980 |
|
|
2,980 |
|
Other |
|
29,643 |
|
|
11,546 |
|
Total
current liabilities |
|
136,984 |
|
|
86,609 |
|
Long-term debt |
|
1,330,801 |
|
|
1,161,394 |
|
Asset retirement
obligation |
|
268,783 |
|
|
269,168 |
|
Fair value of
derivatives |
|
— |
|
|
4,091 |
|
Other long-term
liabilities |
|
643 |
|
|
643 |
|
Total liabilities |
|
1,737,211 |
|
|
1,521,905 |
|
Commitments and
contingencies |
|
|
|
|
Partners' deficit |
|
|
|
|
Series A
Preferred equity - 2,300,000 units issued and outstanding at
September 30, 2017 and December 31, 2016 |
|
55,192 |
|
|
55,192 |
|
Series B
Preferred equity - 7,200,000 units issued and outstanding at
September 30, 2017 and December 31, 2016 |
|
174,261 |
|
|
174,261 |
|
Incentive
distribution equity - 100,000 units issued and outstanding at
September 30, 2017 and December 31, 2016 |
|
30,814 |
|
|
30,814 |
|
Limited
partners' deficit - 72,594,620 and 72,056,097 units issued and
outstanding at September 30, 2017 and December 31, 2016,
respectively |
|
(507,335 |
) |
|
(482,200 |
) |
General
partner's deficit (approximately 0.03%) |
|
(153 |
) |
|
(146 |
) |
Total
partners' deficit |
|
(247,221 |
) |
|
(222,079 |
) |
Total liabilities and
partners' deficit |
|
$ |
1,489,990 |
|
|
$ |
1,299,826 |
|
|
|
|
|
|
|
|
|
|
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 |
|
Nine Months Ended |
|
September 30, |
|
September 30, |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
|
|
Net income
(loss) |
$ |
(33,866 |
) |
|
$ |
(4,303 |
) |
|
$ |
(28,571 |
) |
|
$ |
48,766 |
|
Plus: |
|
|
|
|
|
|
|
Interest
expense |
23,621 |
|
|
17,080 |
|
|
64,368 |
|
|
62,558 |
|
Gain on
extinguishment of debt |
— |
|
|
— |
|
|
— |
|
|
(150,802 |
) |
Income
tax expense |
266 |
|
|
223 |
|
|
837 |
|
|
710 |
|
Depletion, depreciation, amortization and accretion |
33,715 |
|
|
36,068 |
|
|
90,200 |
|
|
110,695 |
|
Impairment of long-lived assets |
14,665 |
|
|
4,618 |
|
|
24,548 |
|
|
20,065 |
|
(Gain)
loss on disposal of assets |
(2,034 |
) |
|
(8,447 |
) |
|
3,491 |
|
|
(49,289 |
) |
Equity in
(income) loss of equity method investees |
— |
|
|
(7 |
) |
|
(12 |
) |
|
7 |
|
Unit-based compensation expense |
1,551 |
|
|
1,445 |
|
|
4,931 |
|
|
5,612 |
|
Minimum
payments received in excess of overriding royalty interest
earned(1) |
512 |
|
|
423 |
|
|
1,427 |
|
|
1,225 |
|
Net
(gains) losses on commodity derivatives |
13,309 |
|
|
(18,326 |
) |
|
(35,876 |
) |
|
2,311 |
|
Net cash
settlements received on commodity derivatives |
6,972 |
|
|
11,613 |
|
|
17,779 |
|
|
56,483 |
|
Transaction related expenses |
54 |
|
|
296 |
|
|
138 |
|
|
1,087 |
|
Adjusted
EBITDA |
$ |
58,765 |
|
|
$ |
40,683 |
|
|
$ |
143,260 |
|
|
$ |
109,428 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 LPDan WestcottExecutive Vice President
and Chief Financial Officer(432) 689-5200
Legacy Reserves Inc. (MM) (NASDAQ:LGCY)
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