Legacy Reserves LP ("Legacy") (NASDAQ:LGCY) today announced second
quarter results for 2017 including the following Q2 highlights:
- Brought online an additional 9 horizontal wells in Howard
County, TX and Lea County, NM under our Joint Development Agreement
("JDA"), representing 33 horizontal wells brought online since
commencement of the program.
- Closed $3.8 million of acreage acquisitions in Howard County,
Texas, extending lateral lengths and further coring up our
position.
- Generated net income of $5.3 million in the first half of 2017
and a net loss of $11.1 million in Q2 2017.
- Generated EBITDA of $44.3 million representing a 10% increase
compared to Q1 2017.
- Reduced lease operating expenses, excluding ad valorem taxes,
to $42.3 million representing a 14% decrease compared to Q1
2017.
- Amended and restated our Joint Development Agreement ("JDA")
with TPG Sixth Street Partners ("TSSP") including a $141 million
acceleration payment increasing our working interest from 20% to
85% in Tranche 1 wells and from 20% to 66.3% in any subsequent
tranches.
- Increased our 2017 capital budget to $205 million to fund our
increased Permian drilling activity and higher post-reversion JDA
working interest.
Paul T. Horne, Chairman of the Board, President
and Chief Executive Officer of Legacy's general partner commented,
“We are pleased to announce our acceleration payment and amended
development agreement. Our horizontal Permian development has been
a big success for both us and TSSP. As a result of the amended
development agreement, we are able to increase our exposure to this
highly-profitable resource, thereby allowing for a meaningful
production growth program for the benefit of our equity holders
that is expected to positively impact financial leverage ratios
over time. We are thankful for TSSP's continued support within the
program and for the company as a whole. In addition to our focus on
these development projects, we concentrated this quarter on
decreasing lifting costs after a heightened level of activity in
the first quarter repairing and returning wells to production.
These costs were down 14% sequentially, meeting the ambitious goal
we set at last quarter’s conference call.
Dan Westcott, Executive Vice President and Chief
Financial Officer of Legacy’s general partner, commented, “Today
marks another significant step in our transition to a
growth-oriented operator focused on efficiently developing our
tremendous opportunity set. While these activities are free cash
flow negative in the short-term, the long-term profile of our
development should improve our leverage metrics over time through
meaningful growth in EBITDA. In particular, our revised 2017
Financial Guidance shows estimated 61% and 63% growth in oil
production and EBITDA, respectively, in the second half of 2017
relative to the first, driven by our increased participation in our
ongoing horizontal development program under the JDA. Despite
funding this acquisition under our $300 million 2nd lien term loan,
we expect our total leverage to decrease by over 1.0x from Q2
actual to year-end pro forma. These additional interests add
considerable value supporting our borrowing base which, given the
transaction, is under review. We currently maintain $129.1
million of liquidity under that borrowing base and also have $95
million of additional availability under the 2nd lien term loan
through late October. Our team is excited to be able to
harness more of this Permian growth opportunity and anticipates
continued organic growth in 2018.”
$141 million Acceleration Payment and
Amended and Restated Joint Development Agreement
On August 1, we entered into an agreement to
make an acceleration payment to acquire by reversion certain of
TSSP’s pre-reversion interests in the 48 Tranche 1 wells for $141
million, with proceeds from our 2nd lien term loan with GSO Capital
Partners (“GSO”). The acceleration payment will cause Legacy’s
interest in these wells to increase from 20% to 85% of the parties'
combined working interest, effective August 1, 2017. We estimate
the purchase price represents approximately 2.5x 2017E EBITDA,
substantially improving our pro forma credit profile.
As part of the amended and restated JDA, TSSP
will fund 40% of the parties' development costs in the next tranche
of 16 wells for 33.7% of the parties' combined working interest
thereby providing Legacy with a greater participation in future
horizontal Permian development (60% funding for a 66.3% working
interest). TSSP will have the option to elect to fund an
additional tranche of 10 wells on identical terms and will also
have the opportunity to participate in a maximum of 6 additional
wells per tranche within the defined area of mutual interest.
TSSP’s post-reversionary working interest (after a 15% internal
rate of return with respect to such tranche) has also been
proportionately reduced from 15% to 6.3% in the two remaining
tranches.
Revised Capital Expenditure
Budget
In association with the amended and restated JDA
and acceleration payment thereunder, we will incur a much greater
percentage of the gross development capital under the JDA on a
go-forward basis. After making the acceleration payment, we became
responsible for 85% of all remaining Tranche 1 capital costs to be
paid regardless of when such costs were incurred.
2017E Capital Program by Category ($ in
millions) |
|
|
|
|
Gross |
|
Net |
|
Percent of Net |
Horizontal Permian
drilling |
|
$ |
327 |
|
|
$ |
185 |
|
|
90 |
% |
Other drilling |
|
4 |
|
|
2 |
|
|
1 |
% |
Other workovers |
|
13 |
|
|
9 |
|
|
4 |
% |
East Texas (workovers,
G&P, facilities) |
|
6 |
|
|
6 |
|
|
3 |
% |
CO2 + other
facilities |
|
3 |
|
|
3 |
|
|
2 |
% |
Total capital
expenditures |
|
$ |
353 |
|
|
$ |
205 |
|
|
100 |
% |
Updated 2017 Guidance
The following table sets forth certain
assumptions used by Legacy to estimate its anticipated results of
operations for 2017. These estimates do not include any
acquisitions of additional oil or natural gas properties. In
addition, these estimates are based on, among other things,
assumptions of capital expenditure levels, current indications of
supply and demand for oil and natural gas and current operating and
labor costs. The guidance set forth below does not constitute any
form of guarantee, assurance or promise that the matters indicated
will actually be achieved. The guidance below sets forth
management’s best estimate based on current and anticipated market
conditions and other factors. While we believe that these estimates
and assumptions are reasonable, they are inherently uncertain and
are subject to, among other things, significant business, economic,
regulatory, environmental and competitive risks and uncertainties
that could cause actual results to differ materially from those we
anticipate, as set forth under “Cautionary Statement Relevant to
Forward-Looking Information.”
|
|
Second Half 2017E Range |
|
FY 2017E Range(1) |
|
|
|
|
|
|
|
|
|
|
|
($ in thousands unless otherwise noted) |
Production: |
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
3,300 |
- |
3,400 |
|
5,381 |
- |
5,481 |
Natural gas liquids
(MGal) |
|
17,300 |
- |
17,700 |
|
33,467 |
- |
33,867 |
Natural gas (MMcf) |
|
32,000 |
- |
32,800 |
|
63,196 |
- |
63,996 |
Total (MBoe) |
|
9,045 |
- |
9,288 |
|
16,711 |
- |
16,953 |
Average daily
production (Boe/d) |
|
49,158 |
- |
50,478 |
|
45,784 |
- |
46,447 |
|
|
|
|
|
|
|
|
|
Weighted
Average NYMEX Differentials: |
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$(4.25) |
- |
$(3.75) |
|
$(4.22) |
- |
$(3.91) |
NGL realization
(2) |
|
1.00% |
- |
1.20% |
|
1.11% |
- |
1.22% |
Natural gas (per
Mcf) |
|
$(0.30) |
- |
$(0.20) |
|
$(0.29) |
- |
$(0.24) |
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
Oil and natural gas
production expenses ($/Boe) |
|
$10.00 |
- |
$10.25 |
|
$10.89 |
- |
$11.01 |
Ad valorem and
production taxes (% of revenue) |
|
7.00% |
- |
7.50% |
|
6.86% |
- |
7.14% |
Cash G&A expenses
(3) |
|
$17,000 |
- |
$18,000 |
|
$32,668 |
- |
$33,668 |
|
|
|
|
|
|
|
|
|
Capital
expenditures: |
|
$140,000 |
- |
$157,000 |
|
$188,315 |
- |
$205,000 |
|
|
|
|
|
|
|
|
|
Adjusted
EBITDA(4): |
|
$130,000 |
- |
$145,000 |
|
$214,497 |
- |
$229,497 |
(1) Represents 1H'17 actuals plus 2H'17 estimates.
(2) Represents the projected percentage of WTI crude oil price
per gallon of NGLs.
(3) Consistent with our definition of Adjusted EBITDA, these
figures exclude LTIP and transaction-related expenses.
(4) Adjusted EBITDA is a Non-GAAP financial measure. This
measure does not include pro forma adjustments permitted under our
credit agreements relating to acquired and divested oil or gas
properties. A reconciliation of this measure to the nearest
comparable GAAP measure is available on our website.
Note: Figures above assume NYMEX strip pricing at 7/31/2017
(2H'17 average oil $49.12 / $2.94 natural gas & 2017 average
oil $49.52 / $3.01 natural gas).
LEGACY RESERVES LP |
SELECTED FINANCIAL AND OPERATING DATA |
|
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands, except per unit data) |
Revenues: |
|
|
|
|
|
|
|
|
Oil
sales |
|
$ |
46,096 |
|
|
$ |
41,272 |
|
|
$ |
95,238 |
|
|
$ |
71,592 |
|
Natural
gas liquids (NGL) sales |
|
4,921 |
|
|
3,922 |
|
|
9,971 |
|
|
6,375 |
|
Natural
gas sales |
|
41,830 |
|
|
28,173 |
|
|
87,185 |
|
|
61,259 |
|
Total
revenue |
|
$ |
92,847 |
|
|
$ |
73,367 |
|
|
$ |
192,394 |
|
|
$ |
139,226 |
|
Expenses: |
|
|
|
|
|
|
|
|
Oil and
natural gas production, excluding ad valorem taxes |
|
$ |
42,262 |
|
|
$ |
41,520 |
|
|
$ |
91,490 |
|
|
$ |
88,181 |
|
Ad
valorem taxes |
|
$ |
2,540 |
|
|
$ |
3,041 |
|
|
$ |
4,529 |
|
|
$ |
6,403 |
|
Total oil
and natural gas production |
|
$ |
44,802 |
|
|
$ |
44,561 |
|
|
$ |
96,019 |
|
|
$ |
94,584 |
|
Production and other taxes |
|
$ |
4,145 |
|
|
$ |
3,390 |
|
|
$ |
8,304 |
|
|
$ |
5,963 |
|
General
and administrative, excluding trans. related costs and LTIP |
|
$ |
7,046 |
|
|
$ |
7,777 |
|
|
$ |
15,669 |
|
|
$ |
15,469 |
|
Transaction related costs |
|
$ |
52 |
|
|
$ |
714 |
|
|
$ |
84 |
|
|
$ |
791 |
|
LTIP
expense |
|
$ |
1,483 |
|
|
$ |
2,502 |
|
|
$ |
3,380 |
|
|
$ |
4,167 |
|
Total
general and administrative |
|
$ |
8,581 |
|
|
$ |
10,993 |
|
|
$ |
19,133 |
|
|
$ |
20,427 |
|
Depletion, depreciation, amortization and accretion |
|
$ |
27,689 |
|
|
$ |
37,668 |
|
|
$ |
56,485 |
|
|
$ |
74,627 |
|
Commodity derivative
cash settlements: |
|
|
|
|
|
|
|
|
Oil
derivative cash settlements received |
|
$ |
3,559 |
|
|
$ |
9,760 |
|
|
$ |
6,698 |
|
|
$ |
22,345 |
|
Natural
gas derivative cash settlements received |
|
$ |
3,012 |
|
|
$ |
12,333 |
|
|
$ |
4,109 |
|
|
$ |
22,525 |
|
Production: |
|
|
|
|
|
|
|
|
Oil
(MBbls) |
|
1,044 |
|
|
1,039 |
|
|
2,081 |
|
|
2,108 |
|
Natural
gas liquids (MGal) |
|
8,514 |
|
|
9,663 |
|
|
16,167 |
|
|
17,904 |
|
Natural
gas (MMcf) |
|
15,604 |
|
|
16,743 |
|
|
31,196 |
|
|
34,009 |
|
Total
(MBoe) |
|
3,847 |
|
|
4,060 |
|
|
7,665 |
|
|
8,202 |
|
Average
daily production (Boe/d) |
|
42,275 |
|
|
44,615 |
|
|
42,348 |
|
|
45,066 |
|
Average sales price per
unit (excluding derivative cash settlements): |
|
|
|
|
|
|
|
|
Oil price
(per Bbl) |
|
$ |
44.15 |
|
|
$ |
39.72 |
|
|
$ |
45.77 |
|
|
$ |
33.96 |
|
Natural
gas liquids price (per Gal) |
|
$ |
0.58 |
|
|
$ |
0.41 |
|
|
$ |
0.62 |
|
|
$ |
0.36 |
|
Natural
gas price (per Mcf) |
|
$ |
2.68 |
|
|
$ |
1.68 |
|
|
$ |
2.79 |
|
|
$ |
1.80 |
|
Combined
(per Boe) |
|
$ |
24.13 |
|
|
$ |
18.07 |
|
|
$ |
25.10 |
|
|
$ |
16.97 |
|
Average sales price per
unit (including derivative cash settlements): |
|
|
|
|
|
|
|
|
Oil price
(per Bbl) |
|
$ |
47.56 |
|
|
$ |
49.12 |
|
|
$ |
48.98 |
|
|
$ |
44.56 |
|
Natural
gas liquids price (per Gal) |
|
$ |
0.58 |
|
|
$ |
0.41 |
|
|
$ |
0.62 |
|
|
$ |
0.36 |
|
Natural
gas price (per Mcf) |
|
$ |
2.87 |
|
|
$ |
2.42 |
|
|
$ |
2.93 |
|
|
$ |
2.46 |
|
Combined
(per Boe) |
|
$ |
25.84 |
|
|
$ |
23.51 |
|
|
$ |
26.51 |
|
|
$ |
22.45 |
|
Average WTI oil spot
price (per Bbl) |
|
$ |
48.10 |
|
|
$ |
45.46 |
|
|
$ |
49.85 |
|
|
$ |
39.55 |
|
Average Henry Hub
natural gas index price (per MMbtu) |
|
$ |
3.08 |
|
|
$ |
2.15 |
|
|
$ |
3.05 |
|
|
$ |
2.07 |
|
Average unit costs per
Boe: |
|
|
|
|
|
|
|
|
Oil and
natural gas production, excluding ad valorem taxes |
|
$ |
10.99 |
|
|
$ |
10.23 |
|
|
$ |
11.94 |
|
|
$ |
10.75 |
|
Ad
valorem taxes |
|
$ |
0.66 |
|
|
$ |
0.75 |
|
|
$ |
0.59 |
|
|
$ |
0.78 |
|
Production and other taxes |
|
$ |
1.08 |
|
|
$ |
0.83 |
|
|
$ |
1.08 |
|
|
$ |
0.73 |
|
General
and administrative excluding trans. related costs and LTIP |
|
$ |
1.83 |
|
|
$ |
1.92 |
|
|
$ |
2.04 |
|
|
$ |
1.89 |
|
Total
general and administrative |
|
$ |
2.23 |
|
|
$ |
2.71 |
|
|
$ |
2.50 |
|
|
$ |
2.49 |
|
Depletion, depreciation, amortization and accretion |
|
$ |
7.20 |
|
|
$ |
9.28 |
|
|
$ |
7.37 |
|
|
$ |
9.10 |
|
Financial and Operating Results - Three-Month Period
Ended June 30, 2017 Compared to Three-Month Period Ended
June 30, 2016
- Production decreased 5% to 42,275 Boe/d from 44,615 Boe/d
primarily due to natural production declines and individually
immaterial divestitures completed in 2016 and 2017. This decline
was partially offset by additional production from our drilling
operations in Howard County, Texas and Lea County, New Mexico.
- Average realized price, excluding net cash settlements from
commodity derivatives, increased 34% to $24.13 per Boe in 2017 from
$18.07 per Boe in 2016 driven by the significant increase in
commodity prices. Average realized oil price increased 11% to
$44.15 in 2017 from $39.72 in 2016 driven by an increase in the
average West Texas Intermediate ("WTI") crude oil price of $2.64
per Bbl and improving regional differentials. Average realized
natural gas price increased 60% to $2.68 per Mcf in 2017 from $1.68
per Mcf in 2016. This increase is primarily a result of the
increase in average Henry Hub natural gas index price of $0.93 per
Mcf. Finally, our average realized NGL price increased 41% to $0.58
per gallon in 2017 from $0.41 per gallon in 2016.
- Production expenses, excluding ad valorem taxes, increased 2%
to $42.3 million in 2017 from $41.5 million in 2016, primarily due
to increased workover and repair activity across all operating
regions. On an average cost per Boe basis, production expenses
excluding ad valorem taxes increased 7% to $10.99 per Boe in 2017
from $10.23 per Boe in 2016.
- Non-cash impairment expense was $1.8 million in Q2 2017. This
impairment was primarily caused by increased expenses in 4 separate
producing fields.
- General and administrative expenses, excluding unit-based
Long-Term Incentive Plan compensation expense, decreased to $7.1
million in 2017 from $8.5 million in 2016 due to general cost
reduction efforts.
- Cash settlements received on our commodity derivatives during
2017 were $6.6 million compared to $22.1 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 Q2
2017 compared to Q2 2016 as well as lower contracted hedge
prices.
- Total development capital expenditures increased to $24.6
million in 2017 from $6.9 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.
Financial and Operating Results - Six-Month Period Ended
June 30, 2017 Compared to Six-Month Period Ended June 30,
2016
- Production decreased 6% to 42,348 Boe/d from 45,066 Boe/d
primarily due to natural production declines and individually
immaterial divestitures partially offset by growth from our
development activity.
- Average realized price, excluding net cash settlements from
commodity derivatives, increased 48% to $25.10 per Boe in 2017 from
$16.97 per Boe in 2016 driven by the significant increase in
commodity prices. Average realized oil price increased 35% to
$45.77 in 2017 from $33.96 in 2016 driven by an increase in the
average WTI crude oil price of $10.30 per Bbl and improving
regional differentials. Average realized natural gas price
increased 55% to $2.79 per Mcf in 2017 from $1.80 per Mcf in 2016.
This increase is a result of the increase in the average Henry Hub
natural gas index price of approximately $0.98 per Mcf. Finally,
our average realized NGL price increased 73% to $0.62 per gallon in
2017 from $0.36 per gallon in 2016.
- Production expenses, excluding ad valorem taxes, increased 4%
to $91.5 million in 2017 from $88.2 million in 2016. On an average
cost per Boe basis, production expenses increased 11% to $11.94 per
Boe in 2017 from $10.75 per Boe in 2016. The increased expenses
were primarily due to higher workover and repair activity across
all operating regions.
- Non-cash impairment expense totaled $9.9 million in 2017 driven
by the continued decline in commodities futures prices and
increased expenses. Impairment expense totaled $15.4 million in
2016 due to the decline in commodities futures prices in 2016.
- General and administrative expenses, excluding unit-based LTIP
compensation expense totaled $15.8 million in 2017 compared to
$16.3 million in 2016, reflecting general cost reduction
efforts.
- Cash settlements received on our commodity derivatives during
2017 were $10.8 million compared to $44.9 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 $48.3
million in 2017 from $11.7 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 August 1, 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 |
July-December 2017 |
|
92,000 |
|
|
$84.75 |
|
$84.75 |
2018 |
|
730,000 |
|
|
$55.04 |
|
$55.00 |
- |
$55.15 |
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 |
July-December 2017 |
|
1,104,000 |
|
$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 |
July-December 2017 |
|
92,000 |
|
|
$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 |
July-December 2017 |
|
1,104,000 |
|
|
$(0.30) |
|
$(0.75) |
- |
$(0.05) |
2018 |
|
2,190,000 |
|
|
$(1.22) |
|
$(1.25) |
- |
$(1.15) |
2019 |
|
730,000 |
|
|
$(1.15) |
|
$(1.15) |
Natural Gas Swaps (Henry Hub):
|
|
|
|
Average |
|
Price Range per |
Time Period |
|
Volumes (MMBtu) |
|
Price per MMBtu |
|
MMBtu |
July-December 2017 |
|
13,800,000 |
|
|
$3.36 |
|
$3.29 |
- |
$3.39 |
2018 |
|
42,200,000 |
|
|
$3.25 |
|
$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 |
July-December 2017 |
|
7,360,000 |
|
$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 |
July-December 2017 |
|
2,520,000 |
|
$3.75 |
|
$4.25 |
|
$5.53 |
Natural Gas Basis Swaps (NWPL, SoCal and San Juan):
|
|
July-December 2017 |
|
|
|
|
Average |
|
|
Volumes (MMBtu) |
|
Price per MMBtu |
NWPL |
|
3,680,000 |
|
$(0.16) |
SoCal |
|
1,260,400 |
|
$0.11 |
San Juan |
|
1,260,400 |
|
$(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 August 2, 2017.
Conference Call
As announced on July 19, 2017, Legacy will host
an investor conference call to discuss Legacy's results on
Thursday, August 3, 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, August 10,
2017, by dialing 855-859-2056 or 404-537-3406 and entering replay
code 53352520. 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 |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
|
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands, except per unit
data) |
Revenues: |
|
|
|
|
|
|
|
|
Oil
sales |
|
$ |
46,096 |
|
|
$ |
41,272 |
|
|
$ |
95,238 |
|
|
$ |
71,592 |
|
Natural
gas liquids (NGL) sales |
|
4,921 |
|
|
3,922 |
|
|
9,971 |
|
|
6,375 |
|
Natural
gas sales |
|
41,830 |
|
|
28,173 |
|
|
87,185 |
|
|
61,259 |
|
Total
revenues |
|
92,847 |
|
|
73,367 |
|
|
192,394 |
|
|
139,226 |
|
|
|
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
|
|
Oil and
natural gas production |
|
44,802 |
|
|
44,561 |
|
|
96,019 |
|
|
94,584 |
|
Production and other taxes |
|
4,145 |
|
|
3,390 |
|
|
8,304 |
|
|
5,963 |
|
General
and administrative |
|
8,581 |
|
|
10,993 |
|
|
19,133 |
|
|
20,427 |
|
Depletion, depreciation, amortization and accretion |
|
27,689 |
|
|
37,668 |
|
|
56,485 |
|
|
74,627 |
|
Impairment of long-lived assets |
|
1,821 |
|
|
— |
|
|
9,883 |
|
|
15,447 |
|
(Gain)
loss on disposal of assets |
|
11,049 |
|
|
(9,141 |
) |
|
5,525 |
|
|
(40,842 |
) |
Total
expenses |
|
98,087 |
|
|
87,471 |
|
|
195,349 |
|
|
170,206 |
|
|
|
|
|
|
|
|
|
|
Operating
loss |
|
(5,240 |
) |
|
(14,104 |
) |
|
(2,955 |
) |
|
(30,980 |
) |
|
|
|
|
|
|
|
|
|
Other income
(expense): |
|
|
|
|
|
|
|
|
Interest
income |
|
8 |
|
|
16 |
|
|
9 |
|
|
54 |
|
Interest
expense |
|
(20,614 |
) |
|
(20,302 |
) |
|
(40,747 |
) |
|
(45,478 |
) |
Gain on
extinguishment of debt |
|
— |
|
|
19,998 |
|
|
— |
|
|
150,802 |
|
Equity in
income (loss) of equity method investees |
|
1 |
|
|
(9 |
) |
|
12 |
|
|
(14 |
) |
Net gains
(losses) on commodity derivatives |
|
14,516 |
|
|
(37,675 |
) |
|
49,185 |
|
|
(20,637 |
) |
Other |
|
402 |
|
|
(98 |
) |
|
362 |
|
|
(192 |
) |
Income
(loss) before income taxes |
|
(10,927 |
) |
|
(52,174 |
) |
|
5,866 |
|
|
53,555 |
|
Income tax expense |
|
(150 |
) |
|
(87 |
) |
|
(571 |
) |
|
(487 |
) |
Net
income (loss) |
|
$ |
(11,077 |
) |
|
$ |
(52,261 |
) |
|
$ |
5,295 |
|
|
$ |
53,068 |
|
Distributions to Preferred unitholders |
|
(4,750 |
) |
|
(4,750 |
) |
|
(9,500 |
) |
|
(8,708 |
) |
Net
income (loss) attributable to unitholders |
|
$ |
(15,827 |
) |
|
$ |
(57,011 |
) |
|
$ |
(4,205 |
) |
|
$ |
44,360 |
|
|
|
|
|
|
|
|
|
|
Income
(loss) per unit - basic and diluted |
|
$ |
(0.22 |
) |
|
$ |
(0.81 |
) |
|
$ |
(0.06 |
) |
|
$ |
0.64 |
|
Weighted
average number of units used in computing net income (loss) per
unit - |
|
|
|
|
|
|
|
|
Basic and
diluted |
|
72,354 |
|
|
70,071 |
|
|
72,229 |
|
|
69,518 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LEGACY RESERVES LP |
CONDENSED CONSOLIDATED BALANCE SHEETS |
(UNAUDITED) |
|
ASSETS |
|
|
June 30, 2017 |
|
December 31, 2016 |
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Current assets: |
|
|
|
|
Cash and
cash equivalents |
|
$ |
1,214 |
|
|
$ |
2,555 |
|
Accounts
receivable, net: |
|
|
|
|
Oil and
natural gas |
|
42,189 |
|
|
43,192 |
|
Joint
interest owners |
|
26,673 |
|
|
23,414 |
|
Other |
|
401 |
|
|
2 |
|
Fair
value of derivatives |
|
24,343 |
|
|
6,162 |
|
Prepaid
expenses and other current assets |
|
8,457 |
|
|
7,447 |
|
Total
current assets |
|
103,277 |
|
|
82,772 |
|
Oil and natural gas
properties using the successful efforts method, at cost: |
|
|
|
|
Proved
properties |
|
3,276,421 |
|
|
3,305,856 |
|
Unproved
properties |
|
22,287 |
|
|
13,448 |
|
Accumulated depletion, depreciation, amortization and
impairment |
|
(2,125,166 |
) |
|
(2,137,395 |
) |
|
|
1,173,542 |
|
|
1,181,909 |
|
Other property and
equipment, net of accumulated depreciation and amortization of
$11,047 and $10,412, respectively |
|
2,898 |
|
|
3,423 |
|
Operating rights, net
of amortization of $5,567 and $5,369, respectively |
|
1,449 |
|
|
1,648 |
|
Fair value of
derivatives |
|
27,767 |
|
|
20,553 |
|
Other assets |
|
8,452 |
|
|
8,874 |
|
Investments in equity
method investees |
|
658 |
|
|
647 |
|
Total assets |
|
$ |
1,318,043 |
|
|
$ |
1,299,826 |
|
LIABILITIES AND PARTNERS' DEFICIT |
Current
liabilities: |
|
|
|
|
Accounts
payable |
|
$ |
8,983 |
|
|
$ |
9,092 |
|
Accrued
oil and natural gas liabilities |
|
61,767 |
|
|
53,248 |
|
Fair
value of derivatives |
|
94 |
|
|
9,743 |
|
Asset
retirement obligation |
|
2,980 |
|
|
2,980 |
|
Other |
|
9,016 |
|
|
11,546 |
|
Total
current liabilities |
|
82,840 |
|
|
86,609 |
|
Long-term debt |
|
1,180,047 |
|
|
1,161,394 |
|
Asset retirement
obligation |
|
268,803 |
|
|
269,168 |
|
Fair value of
derivatives |
|
— |
|
|
4,091 |
|
Other long-term
liabilities |
|
643 |
|
|
643 |
|
Total liabilities |
|
1,532,333 |
|
|
1,521,905 |
|
Commitments and
contingencies |
|
|
|
|
Partners' deficit |
|
|
|
|
Series A
Preferred equity - 2,300,000 units issued and outstanding at June
30, 2017 and December 31, 2016 |
|
55,192 |
|
|
55,192 |
|
Series B
Preferred equity - 7,200,000 units issued and outstanding at June
30, 2017 and December 31, 2016 |
|
174,261 |
|
|
174,261 |
|
Incentive
distribution equity - 100,000 units issued and outstanding at June
30, 2017 and December 31, 2016 |
|
30,814 |
|
|
30,814 |
|
Limited
partners' deficit - 72,559,430 and 72,056,097 units issued and
outstanding at June 30, 2017 and December 31, 2016,
respectively |
|
(474,412 |
) |
|
(482,200 |
) |
General
partner's deficit (approximately 0.03%) |
|
(145 |
) |
|
(146 |
) |
Total
partners' deficit |
|
(214,290 |
) |
|
(222,079 |
) |
Total liabilities and
partners' deficit |
|
$ |
1,318,043 |
|
|
$ |
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 |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
|
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Net income
(loss) |
|
$ |
(11,077 |
) |
|
$ |
(52,261 |
) |
|
$ |
5,295 |
|
|
$ |
53,068 |
|
Plus: |
|
|
|
|
|
|
|
|
Interest
expense |
|
20,614 |
|
|
20,302 |
|
|
40,747 |
|
|
45,478 |
|
Gain on
extinguishment of debt |
|
— |
|
|
(19,998 |
) |
|
— |
|
|
(150,802 |
) |
Income
tax expense |
|
150 |
|
|
87 |
|
|
571 |
|
|
487 |
|
Depletion, depreciation, amortization and accretion |
|
27,689 |
|
|
37,668 |
|
|
56,485 |
|
|
74,627 |
|
Impairment of long-lived assets |
|
1,821 |
|
|
— |
|
|
9,883 |
|
|
15,447 |
|
(Gain)
loss on disposal of assets |
|
11,049 |
|
|
(9,141 |
) |
|
5,525 |
|
|
(40,842 |
) |
Equity in
(income) loss of equity method investees |
|
(1 |
) |
|
9 |
|
|
(12 |
) |
|
14 |
|
Unit-based compensation expense |
|
1,483 |
|
|
2,502 |
|
|
3,380 |
|
|
4,167 |
|
Minimum
payments received in excess of overriding royalty interest
earned(1) |
|
470 |
|
|
— |
|
|
915 |
|
|
802 |
|
Net
(gains) losses on commodity derivatives |
|
(14,516 |
) |
|
37,675 |
|
|
(49,185 |
) |
|
20,637 |
|
Net cash
settlements received on commodity derivatives |
|
6,571 |
|
|
22,093 |
|
|
10,807 |
|
|
44,870 |
|
Transaction related expenses |
|
52 |
|
|
714 |
|
|
84 |
|
|
791 |
|
Adjusted
EBITDA |
|
$ |
44,305 |
|
|
$ |
39,650 |
|
|
$ |
84,495 |
|
|
$ |
68,744 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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
Executive Vice President and Chief Financial Officer
432-689-5200
Legacy Reserves Inc. (MM) (NASDAQ:LGCY)
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