Legacy Reserves LP ("Legacy") (NASDAQ:LGCY) today announced fourth
quarter and annual results for 2016. 2016 included the following
highlights:
- Generated record annual production of 43,803 Boe/d up 14% from
38,523 Boe/d in 2015
- Reduced production expenses, excluding ad valorem taxes, by
$13.4 million or 7% relative to 2015 and reported record-low
LOE/Boe of $10.59
- Sold $97.4 million of assets that generated combined annualized
negative cash flow in 26 transactions
- Reduced total debt by $269.4 million and projected annualized
interest expense by $11.7 million
- Entered into a new Second Lien Term Loan Facility with GSO
Capital Partners LP ("GSO") providing $300.0 million of committed
capital, of which $60 million has been drawn
- Restarted horizontal Permian drilling with an increased capital
commitment from TPG Special Situation Partners to a total of $275.0
million and 48 wells -- Currently operating two horizontal
rigs under the JDA program; one in Lea County, NM and one in Howard
County, TX -- Completed nine additional horizontal wells since
recommencing drilling operations in June 2016, resulting in 24
total horizontal wells brought online since initiating the program
in July 2015
Paul T. Horne, Chairman of the Board, President
and Chief Executive Officer, commented, “Our company accomplished
several key objectives in 2016. Despite a very difficult
commodity price environment, 50% and 32% below the average over the
prior five years for oil and natural gas, respectively, we
reduced debt by $269 million by rationalizing non-core assets and
using a portion of the proceeds to repurchase debt at a discount,
drilling tremendous horizontal wells in the Permian, and raising a
new 2nd Lien facility to help fund any future capital needs. For
2017, we are planning a $55 million capital budget based on a very
active, 92% operated gross capital budget of $225.0 million,
focused primarily on our horizontal Permian development. Such
development, including the 24 wells we have drilled, completed and
brought online under our Development Agreement, provides us with
great encouragement for our significant Permian inventory. Despite
this recent success, our balance sheet remains
over-levered."
"Given the significant commodity price downturn
and corresponding upheaval of the upstream MLP market, we
anticipate the continued suspension of distributions and will focus
on growing unitholder value by growing asset value. Our unique
blend of stable, low-decline PDP combined with high-impact Permian
horizontal development presents a distinctive opportunity for us
that we intend to grow for the benefit of our unitholders.”
Dan Westcott, Executive Vice President and Chief
Financial Officer, commented, “I am proud of the team effort that
enabled such great execution this past year. While we certainly are
not out of the woods yet, the recent rise in commodity prices and
our horizontal drilling success that has helped delineate our
tremendous horizontal potential across the Permian gives us great
promise of a brighter future. We look forward to continuing to
delever the balance sheet, exploiting our Permian opportunities and
finding new successes in 2017 and beyond."
Proved Reserves
The following information represents estimates
of our proved reserves as of December 31, 2016 which have been
prepared in compliance with the SEC rules using an average WTI
price, as posted by Plains Marketing L.P., of $39.25 per Bbl for
oil and an average natural gas price, as posted by Platts Gas
Daily, of $2.48 per MMBtu. Using the five-year average forward
price as of February 14, 2017 for both WTI oil and NYMEX natural
gas, we estimate the cumulative projected production from our
year-end proved reserves would increase by approximately 14% to
164.7 MMBoe and the Standardized Measure would increase
approximately 69% to $970.1 million.
|
Operating Regions |
|
Oil (MBbls) |
|
NaturalGas
(MMcf) |
|
NGLs(MBbls) |
|
Total (MBoe) |
|
% Liquids |
|
% PDP |
|
% Total |
|
Standardized Measure($
thousands) |
Permian Basin |
|
25,491 |
|
|
89,446 |
|
|
932 |
|
|
41,331 |
|
|
63.9 |
% |
|
83.4 |
% |
|
28.6 |
% |
|
$ |
280,048 |
|
East Texas |
|
63 |
|
|
339,034 |
|
|
95 |
|
|
56,664 |
|
|
0.3 |
% |
|
98.1 |
% |
|
39.1 |
% |
|
153,976 |
|
Rocky
Mountain |
|
4,970 |
|
|
188,277 |
|
|
4,474 |
|
|
40,823 |
|
|
23.1 |
% |
|
99.2 |
% |
|
28.2 |
% |
|
116,540 |
|
Mid-Continent |
|
1,934 |
|
|
10,263 |
|
|
2,342 |
|
|
5,986 |
|
|
71.4 |
% |
|
95.6 |
% |
|
4.1 |
% |
|
25,062 |
|
Total |
|
32,458 |
|
|
627,020 |
|
|
7,843 |
|
|
144,804 |
|
|
27.8 |
% |
|
94.1 |
% |
|
100.0 |
% |
|
$ |
575,626 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 Capital Program By Category
|
Gross |
|
Net |
|
Percent of Net |
|
(In millions) |
|
|
Horizontal Permian
Drilling |
$ |
197.0 |
|
|
$ |
33.6 |
|
|
61 |
% |
Other Drilling |
4.6 |
|
|
1.1 |
|
|
2 |
% |
Other Workovers |
7.3 |
|
|
4.9 |
|
|
9 |
% |
East Texas (Workovers,
G&P, Facilities) |
7.8 |
|
|
7.7 |
|
|
14 |
% |
CO2 + Other
Facilities |
8.3 |
|
|
7.7 |
|
|
14 |
% |
Total Capital
Expenditures |
$ |
225.0 |
|
|
$ |
55.0 |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
We serve as operator of approximately 92% of our
anticipated capital program, and accordingly, maintain significant
control of the capital program budget and may deviate materially
from the figures above based on market conditions (or
otherwise).
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.”
|
|
FY 2017E Range |
|
|
($ in thousands unless otherwise noted) |
Production: |
|
|
|
|
Oil (MBbls) |
|
|
4,300 |
|
- |
|
4,400 |
|
Natural gas liquids
(MGal) |
|
|
35,800 |
|
- |
|
36,800 |
|
Natural gas (MMcf) |
|
|
61,300 |
|
- |
|
62,900 |
|
Total (MBoe) |
|
|
15,369 |
|
- |
|
15,760 |
|
Average daily
production (Boe/d) |
|
|
42,107 |
|
- |
|
43,178 |
|
|
|
|
|
|
Weighted
Average NYMEX Differentials: |
|
|
|
|
Oil (per Bbl) |
|
$(4.75) |
|
- |
$(4.00) |
|
NGL realization
(1) |
|
|
1.05% |
|
- |
|
1.23% |
|
Natural gas (per
Mcf) |
|
$(0.31) |
|
- |
$(0.26) |
|
|
|
|
|
|
Expenses: |
|
|
|
|
Oil and natural gas
production expenses ($/Boe) |
|
$10.80 |
|
- |
$11.20 |
|
Ad valorem and
production taxes (% of revenue) |
|
|
7.50% |
|
- |
|
8.00% |
|
Cash G&A expenses
(2) |
|
$33,000 |
|
- |
$34,000 |
|
|
|
|
|
|
Capital
expenditures: |
|
$55,000 |
|
|
$60,000 |
|
|
|
|
|
|
Adjusted
EBITDA(3): |
|
$195,000 |
|
- |
$215,000 |
|
(1) Represents the projected percentage of WTI crude oil price
per gallon of NGLs.
(2) Consistent with our definition of Adjusted EBITDA, these
figures exclude LTIP expenses. Cash settlements of LTIP (not
included herein) impact Distributable Cash Flow.
(3) Adjusted EBITDA is a Non-GAAP measure. A non-GAAP
reconciliation is available on our website.
Note: Figures above assume NYMEX strip pricing at 2/14/2017
(2017 Avg Oil $55.24 / $3.24 Gas).
LEGACY RESERVES LPSELECTED FINANCIAL
AND OPERATING DATA |
|
|
Three Months Ended |
|
Twelve Months Ended |
|
December 31, |
|
December 31, |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
|
(In thousands, except per unit
data) |
Revenues |
|
|
|
|
|
|
|
Oil
sales |
$ |
42,164 |
|
|
$ |
40,653 |
|
|
$ |
152,507 |
|
|
$ |
199,841 |
|
Natural
gas liquids sales |
5,574 |
|
|
3,778 |
|
|
15,406 |
|
|
16,645 |
|
Natural
gas sales |
43,853 |
|
|
35,510 |
|
|
146,444 |
|
|
122,293 |
|
Total
revenues |
$ |
91,591 |
|
|
$ |
79,941 |
|
|
$ |
314,357 |
|
|
$ |
338,779 |
|
Expenses: |
|
|
|
|
|
|
|
Oil and
natural gas production |
$ |
41,456 |
|
|
$ |
48,436 |
|
|
$ |
169,755 |
|
|
$ |
183,163 |
|
Ad
valorem taxes |
172 |
|
|
3,169 |
|
|
9,578 |
|
|
11,328 |
|
Total |
$ |
41,628 |
|
|
$ |
51,605 |
|
|
$ |
179,333 |
|
|
$ |
194,491 |
|
Production and other taxes |
$ |
4,318 |
|
|
$ |
3,345 |
|
|
$ |
14,267 |
|
|
$ |
16,383 |
|
General
and administrative excluding transaction costs and LTIP |
$ |
8,237 |
|
|
$ |
8,574 |
|
|
$ |
31,196 |
|
|
$ |
30,919 |
|
Acquisition costs |
4,158 |
|
|
743 |
|
|
5,245 |
|
|
8,919 |
|
LTIP
expense |
1,586 |
|
|
1,689 |
|
|
7,198 |
|
|
6,673 |
|
Total
general and administrative |
$ |
13,981 |
|
|
$ |
11,006 |
|
|
$ |
43,639 |
|
|
$ |
46,511 |
|
Depletion, depreciation, amortization and accretion |
$ |
39,719 |
|
|
$ |
54,952 |
|
|
$ |
150,414 |
|
|
$ |
177,258 |
|
Commodity derivative
cash settlements: |
|
|
|
|
|
|
|
Oil
derivative cash settlements received |
$ |
7,030 |
|
|
$ |
15,298 |
|
|
$ |
37,464 |
|
|
$ |
91,953 |
|
Natural
gas derivative cash settlements received |
992 |
|
|
13,314 |
|
|
27,041 |
|
|
40,972 |
|
Total
commodity derivative cash settlements |
$ |
8,022 |
|
|
$ |
28,612 |
|
|
$ |
64,505 |
|
|
$ |
132,925 |
|
Production: |
|
|
|
|
|
|
|
Oil
(MBbls) |
949 |
|
|
1,088 |
|
|
4,019 |
|
|
4,608 |
|
Natural
gas liquids (MGal) |
9,111 |
|
|
10,874 |
|
|
36,757 |
|
|
42,210 |
|
Natural
gas (MMcf) |
16,243 |
|
|
16,997 |
|
|
66,824 |
|
|
50,687 |
|
Total
(MBoe) |
3,873 |
|
|
4,180 |
|
|
16,032 |
|
|
14,061 |
|
Average
daily production (Boe/d) |
42,098 |
|
|
45,435 |
|
|
43,803 |
|
|
38,523 |
|
Average
sales price per unit (excluding commodity derivative cash
settlements): |
|
|
|
|
Oil price
(per Bbl) |
$ |
44.43 |
|
|
$ |
37.36 |
|
|
$ |
37.95 |
|
|
$ |
43.37 |
|
Natural
gas liquids price (per Gal) |
$ |
0.61 |
|
|
$ |
0.35 |
|
|
$ |
0.42 |
|
|
$ |
0.39 |
|
Natural
gas price (per Mcf)(a) |
$ |
2.70 |
|
|
$ |
2.09 |
|
|
$ |
2.19 |
|
|
$ |
2.41 |
|
Combined
(per Boe) |
$ |
23.65 |
|
|
$ |
19.12 |
|
|
$ |
19.61 |
|
|
$ |
24.09 |
|
Average
sales price per unit (including commodity derivative cash
settlements): |
|
|
|
|
Oil price
(per Bbl) |
$ |
51.84 |
|
|
$ |
51.43 |
|
|
$ |
47.27 |
|
|
$ |
63.32 |
|
Natural
gas liquids price (per Gal) |
$ |
0.61 |
|
|
$ |
0.35 |
|
|
$ |
0.42 |
|
|
$ |
0.39 |
|
Natural
gas price (per Mcf)(a) |
$ |
2.76 |
|
|
$ |
2.87 |
|
|
$ |
2.60 |
|
|
$ |
3.22 |
|
Combined
(per Boe) |
$ |
25.72 |
|
|
$ |
25.97 |
|
|
$ |
23.63 |
|
|
$ |
33.55 |
|
Average WTI oil spot
price (per Bbl) |
$ |
49.14 |
|
|
$ |
41.94 |
|
|
$ |
43.29 |
|
|
$ |
48.66 |
|
Average Henry Hub
natural gas index price (per MMbtu) |
$ |
3.04 |
|
|
$ |
2.12 |
|
|
$ |
2.52 |
|
|
$ |
2.62 |
|
Average unit costs per
Boe: |
|
|
|
|
|
|
|
Production costs, excluding production and other taxes |
$ |
10.70 |
|
|
$ |
11.59 |
|
|
$ |
10.59 |
|
|
$ |
13.03 |
|
Ad
valorem taxes |
$ |
0.04 |
|
|
$ |
0.76 |
|
|
$ |
0.60 |
|
|
$ |
0.81 |
|
Production and other taxes |
$ |
1.11 |
|
|
$ |
0.80 |
|
|
$ |
0.89 |
|
|
$ |
1.17 |
|
General
and administrative excluding LTIP & acquisition costs |
$ |
2.13 |
|
|
$ |
2.05 |
|
|
$ |
1.95 |
|
|
$ |
2.20 |
|
Total
general and administrative |
$ |
3.61 |
|
|
$ |
2.63 |
|
|
$ |
2.72 |
|
|
$ |
3.31 |
|
Depletion, depreciation, amortization and accretion |
$ |
10.26 |
|
|
$ |
13.15 |
|
|
$ |
9.38 |
|
|
$ |
12.61 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Annual Financial and Operating Results -
2016 Compared to 2015
- Production increased 14% to an annual record of 43,803 Boe/d
from 38,523 Boe/d primarily due to a full year of production from
our acquisitions of East Texas properties, partially offset by
individually immaterial divestitures and natural production
declines.
- Average realized price, excluding net cash settlements from
commodity derivatives, decreased 19% to $19.61 per Boe in 2016 from
$24.09 per Boe in 2015. Average realized oil price decreased 12% to
$37.95 in 2016 from $43.37 in 2015. This decrease was primarily
driven by a decrease in the average West Texas Intermediate ("WTI")
crude oil price of $5.37 per Bbl. Average realized natural gas
price decreased 9% to $2.19 per Mcf in 2016 from $2.41 per Mcf in
2015. This decrease was primarily driven by a decrease in the
average Henry Hub natural gas index price of $0.10 per Mcf and an
increase in realized regional differentials. Finally, our average
realized NGL price increased 8% to $0.42 per gallon in 2016 from
$0.39 per gallon in 2015.
- Production expenses, excluding ad valorem taxes, decreased 7%
to $169.8 million in 2016 from $183.2 million in 2015 due to our
cost containment efforts on our historical assets, partially offset
by costs associated with the acquisitions of East Texas properties.
On an average cost per Boe basis, production expenses decreased 19%
to $10.59 per Boe in 2016 from $13.03 per Boe in 2015, driven
primarily by a reduction in the production expenses from our
historical assets as well as the inclusion of lower cost natural
gas properties from our acquisitions of East Texas properties.
- Non-cash impairment expense totaled $61.8 million primarily
driven by well performance and the further decline in oil and
natural gas prices during 2016.
- General and administrative expenses, excluding acquisition
costs and unit-based Long-Term Incentive Plan ("LTIP") compensation
expense totaled $31.2 million in 2016 compared to $30.9 million in
2015. This small increase was primarily attributable to costs
associated with additional personnel commensurate with the growth
of our asset base, partially offset by general cost reduction
efforts.
- Cash settlements received on our commodity derivatives during
2016 were $64.5 million as compared to $132.9 million in 2015.
- Total development capital expenditures decreased to $29.5
million in 2016 from $36.8 million in 2015.
Financial and Operating Results - Fourth
Quarter 2016 Compared to Fourth Quarter 2015
- Production decreased 7% to 42,098 Boe/d from 45,435 Boe/d
primarily due to production decreases related to individually
immaterial divestitures and natural production declines.
- Average realized price, excluding net cash settlements from
commodity derivatives, increased 24% to $23.65 per Boe in 2016 from
$19.12 per Boe in 2015. Average realized oil price increased 19% to
$44.43 per Bbl in 2016 from $37.36 per Bbl in 2015. This increase
of $7.07 was primarily attributable to the increase in the average
WTI crude oil price of $7.20. Average realized natural gas prices
increased 29.2% to $2.70 per Mcf in 2016 from $2.09 per Mcf in
2015. This increase of $0.61 was primarily attributable to a $0.92
increase in the average Henry Hub natural gas price index,
partially offset by higher realized regional differentials.
Finally, our average realized NGL price increased 74% to $0.61 per
gallon in 2016 from $0.35 per gallon in 2015.
- Production expenses, excluding ad valorem taxes, decreased 14%
to $41.5 million in 2016 from $48.4 million in 2015. Production
expenses decreased primarily due to cost reduction efforts on our
historical properties and individually immaterial divestitures. On
a per Boe basis, production expenses decreased to $10.70 from
$11.59 or 8% driven by cost reductions in our ongoing
operations.
- Non-cash impairment expense totaled $41.7 million primarily
driven by well performance during the period.
- General and administrative expenses, excluding acquisition
costs and LTIP compensation expense, decreased to $8.2 million in
2016 from $8.6 million in 2015 due to general cost reduction
efforts.
- Cash settlements received on our commodity derivatives were
$8.0 million during 2016 compared to $28.6 million in 2015.
- Total development capital expenditures were $11.0 million in
the fourth quarter of 2016.
Commodity Derivative
Contracts
We enter into oil and natural gas derivative
contracts to help mitigate the risk of changing commodity prices.
As of February 21, 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:
Calendar Year |
|
Volumes (Bbls) |
|
Average Price per Bbl |
|
Price Range per Bbl |
2017 |
|
182,500 |
|
|
$84.75 |
|
$84.75 |
2018 |
|
730,000 |
|
|
$55.04 |
|
$55.00 |
- |
$55.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI Crude Oil Costless Collars. As an illustrative example, at
an annual WTI market price of $40.00, $50.00 and $65.00, the
summary positions below would result in a net price of $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 |
2017 |
|
2,190,000 |
|
$45.00 |
|
$59.02 |
2018 |
|
1,551,250 |
|
$47.06 |
|
$60.29 |
|
|
|
|
|
|
|
WTI Crude Oil 3-Way Collars. As an illustrative example, at an
annual average WTI market price of $40.00, $50.00 and $65.00, the
summary position below would result in a net price of $65.00,
$75.00 and $85.00, respectively.
|
|
|
|
Average Short Put |
|
Average Long Put |
|
Average Short Call |
Calendar Year |
|
Volumes (Bbls) |
|
Price per Bbl |
|
Price per Bbl |
|
Price per Bbl |
2017 |
|
72,400 |
|
|
$60.00 |
|
$85.00 |
|
$104.20 |
|
|
|
|
|
|
|
|
|
|
Crude Oil Enhanced Swaps. As an illustrative example, at an
annual average WTI market price of $40.00, $50.00 and $65.00, the
summary positions below would result in a net price of $65.85,
$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 |
Calendar Year |
|
Volumes (Bbls) |
|
Price per Bbl |
|
Price per Bbl |
|
Price per Bbl |
2017 |
|
182,500 |
|
|
$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 |
2017 |
|
2,190,000 |
|
|
$(0.30) |
|
|
$(0.75) |
|
- |
$(0.05) |
|
2018 |
|
1,460,000 |
|
|
$(1.25) |
|
|
$(1.25) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Swaps (Henry Hub):
|
|
|
|
Average |
|
Price Range per MMBtu |
Calendar Year |
|
Volumes (MMBtu) |
|
Price per MMBtu |
|
2017 |
|
27,600,000 |
|
|
$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). As an illustrative
example, 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 |
2017 |
|
14,600,000 |
|
$2.90 |
|
$3.44 |
|
|
|
|
|
|
|
Natural Gas 3-Way Collars (Henry Hub). As an illustrative
example, 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 |
Calendar Year |
|
(MMBtu) |
|
Price per MMBtu |
|
Price per MMBtu |
|
Price per MMBtu |
2017 |
|
5,040,000 |
|
$3.75 |
|
$4.25 |
|
$5.53 |
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Basis Swaps (NWPL, SoCal and San
Juan):
|
|
2017 |
|
|
Volumes |
|
Average |
|
|
(MMBtu) |
|
Price per MMBtu |
NWPL |
|
7,300,000 |
|
$(0.16) |
SoCal |
|
2,500,250 |
|
$0.11 |
San Juan |
|
2,500,250 |
|
$(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.
Annual Report on Form 10-K
Our consolidated, audited financial statements
and related footnotes will be available in our annual 2016 Form
10-K which will be filed on or about February 22, 2017.
Conference Call
As announced on February 8, 2017, Legacy will
host an investor conference call to discuss Legacy's results and
corresponding presentation materials on Thursday, February 23, 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, March 2, 2017, by dialing
855-859-2056 or 404-537-3406 and entering replay code 61542356.
Those wishing to listen to the live or archived web cast via the
Internet or view the corresponding presentation materials should go
to the Investor Relations tab of our website at www.legacylp.com.
Following our prepared remarks, we will be pleased to answer
questions from securities analysts and institutional portfolio
managers and analysts; the complete call is open to all other
interested parties on a listen-only basis.
About Legacy Reserves LP
Legacy Reserves LP is a master limited
partnership headquartered in Midland, Texas, focused on the
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 delever 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
expenditure, 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 its 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 LPCONDENSED
CONSOLIDATED STATEMENTS OF
OPERATIONS(UNAUDITED) |
|
|
Three Months Ended |
|
Twelve Months Ended |
|
December 31, |
|
December 31, |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
|
(In thousands, except per unit
data) |
Revenues: |
|
|
|
|
|
|
|
Oil
sales |
$ |
42,164 |
|
|
$ |
40,653 |
|
|
$ |
152,507 |
|
|
$ |
199,841 |
|
Natural
gas liquids (NGL) sales |
5,574 |
|
|
3,778 |
|
|
15,406 |
|
|
16,645 |
|
Natural
gas sales |
43,853 |
|
|
35,510 |
|
|
146,444 |
|
|
122,293 |
|
Total
revenues |
91,591 |
|
|
79,941 |
|
|
314,357 |
|
|
338,779 |
|
Expenses: |
|
|
|
|
|
|
|
Oil and
natural gas production |
41,628 |
|
|
51,605 |
|
|
179,333 |
|
|
194,491 |
|
Production and other taxes |
4,318 |
|
|
3,345 |
|
|
14,267 |
|
|
16,383 |
|
General
and administrative |
13,981 |
|
|
11,006 |
|
|
43,639 |
|
|
46,511 |
|
Depletion, depreciation, amortization and accretion |
39,719 |
|
|
54,952 |
|
|
150,414 |
|
|
177,258 |
|
Impairment of long-lived assets |
41,731 |
|
|
326,349 |
|
|
61,796 |
|
|
633,805 |
|
Gain on
disposal of assets |
(806 |
) |
|
(5,539 |
) |
|
(50,095 |
) |
|
(3,972 |
) |
Total
expenses |
140,571 |
|
|
441,718 |
|
|
399,354 |
|
|
1,064,476 |
|
Operating
loss |
(48,980 |
) |
|
(361,777 |
) |
|
(84,997 |
) |
|
(725,697 |
) |
Other income
(expense): |
|
|
|
|
|
|
|
Interest
income |
13 |
|
|
2 |
|
|
67 |
|
|
329 |
|
Interest
expense |
(16,502 |
) |
|
(17,988 |
) |
|
(79,060 |
) |
|
(76,891 |
) |
Gain on
extinguishment of debt |
— |
|
|
— |
|
|
150,802 |
|
|
— |
|
Equity in
income of equity method investees |
7 |
|
|
29 |
|
|
— |
|
|
126 |
|
Net gains
(losses) on commodity derivatives |
(38,913 |
) |
|
34,270 |
|
|
(41,224 |
) |
|
98,253 |
|
Other |
309 |
|
|
120 |
|
|
(179 |
) |
|
841 |
|
Loss
before income taxes |
(104,066 |
) |
|
(345,344 |
) |
|
(54,591 |
) |
|
(703,039 |
) |
Income tax (expense)
benefit |
(519 |
) |
|
1,208 |
|
|
(1,229 |
) |
|
1,498 |
|
Net
Loss |
$ |
(104,585 |
) |
|
$ |
(344,136 |
) |
|
$ |
(55,820 |
) |
|
$ |
(701,541 |
) |
Distributions to preferred unitholders |
(5,542 |
) |
|
(4,750 |
) |
|
(19,000 |
) |
|
(19,000 |
) |
Net loss
attributable to unitholders |
$ |
(110,127 |
) |
|
$ |
(348,886 |
) |
|
$ |
(74,820 |
) |
|
$ |
(720,541 |
) |
Loss per
unit — basic and diluted |
$ |
(1.53 |
) |
|
$ |
(5.06 |
) |
|
$ |
(1.06 |
) |
|
$ |
(10.45 |
) |
Weighted
average number of units used in |
|
|
|
|
|
|
|
computing
loss per unit — |
|
|
|
|
|
|
|
Basic and
diluted |
72,056 |
|
|
68,950 |
|
|
70,605 |
|
|
68,928 |
|
LEGACY RESERVES LPCONDENSED
CONSOLIDATED BALANCE SHEETS(UNAUDITED) |
|
December 31, |
|
2016 |
|
2015 |
|
(In thousands) |
ASSETS |
Current assets: |
|
|
|
Cash |
$ |
2,555 |
|
|
$ |
2,006 |
|
Accounts
receivable, net: |
|
|
|
Oil and
natural gas |
43,192 |
|
|
33,944 |
|
Joint
interest owners |
23,414 |
|
|
25,378 |
|
Other |
2 |
|
|
86 |
|
Fair
value of derivatives |
6,162 |
|
|
63,711 |
|
Prepaid
expenses and other current assets |
7,447 |
|
|
4,334 |
|
Total
current assets |
82,772 |
|
|
129,459 |
|
Oil and natural gas
properties, at cost: |
|
|
|
Proved
oil and natural gas properties using the successful efforts method
of accounting |
3,305,856 |
|
|
3,485,634 |
|
Unproved
properties |
13,448 |
|
|
13,424 |
|
Accumulated depletion, depreciation, amortization and
impairment |
(2,137,395 |
) |
|
(2,090,102 |
) |
|
1,181,909 |
|
|
1,408,956 |
|
Other property and
equipment, net of accumulated depreciation and amortization
of $10,412 and $8,915, respectively |
3,423 |
|
|
4,575 |
|
Operating rights, net
of amortization of $5,369 and $4,953, respectively |
1,648 |
|
|
2,064 |
|
Fair value of
derivatives |
20,553 |
|
|
56,373 |
|
Other assets |
8,874 |
|
|
11,047 |
|
Investments in equity
method investees |
647 |
|
|
646 |
|
Total assets |
$ |
1,299,826 |
|
|
$ |
1,613,120 |
|
LIABILITIES AND PARTNERS’ EQUITY |
Current
liabilities: |
|
|
|
Accounts
payable |
$ |
9,092 |
|
|
$ |
13,581 |
|
Accrued
oil and natural gas liabilities |
53,248 |
|
|
50,573 |
|
Fair
value of derivatives |
9,743 |
|
|
2,019 |
|
Asset
retirement obligation |
2,980 |
|
|
3,496 |
|
Other |
11,546 |
|
|
11,424 |
|
Total
current liabilities |
86,609 |
|
|
81,093 |
|
Long-term
debt |
1,161,394 |
|
|
1,427,614 |
|
Asset retirement
obligation |
269,168 |
|
|
282,909 |
|
Fair value of
derivatives |
4,091 |
|
|
— |
|
Other long-term
liabilities |
643 |
|
|
1,181 |
|
Total
liabilities |
1,521,905 |
|
|
1,792,797 |
|
Commitments and
contingencies |
|
|
|
Partners’ equity
(deficit): |
|
|
|
Series A
Preferred equity - 2,300,000 units issued and outstanding at
December 31, 2016 and December 31, 2015 |
55,192 |
|
|
55,192 |
|
Series B
Preferred equity - 7,200,000 units issued and outstanding at
December 31, 2016 and December 31, 2015 |
174,261 |
|
|
174,261 |
|
Incentive
distribution equity - 100,000 units issued and outstanding at
December 31, 2016 and December 31, 2015 |
30,814 |
|
|
30,814 |
|
Limited
partners' deficit - 72,056,097 and 68,949,961 units issued and
outstanding at December 31, 2016 and 2015, respectively |
(482,200 |
) |
|
(439,811 |
) |
General
partner’s deficit (approximately 0.03%) |
(146 |
) |
|
(133 |
) |
Total
partners’ deficit |
(222,079 |
) |
|
(179,677 |
) |
Total
liabilities and partners’ deficit |
$ |
1,299,826 |
|
|
$ |
1,613,120 |
|
|
|
|
|
|
|
|
|
Non-GAAP Financial Measures
This press release, the financial tables and
other supplemental information include "Adjusted EBITDA" which is
a non-generally accepted accounting principles ("non-GAAP")
measure which may be used periodically by management when
discussing our financial results with investors and analysts. The
following presents a reconciliation of this non-GAAP financial
measure to its nearest comparable generally accepted accounting
principles ("GAAP") measure.
Adjusted EBITDA is presented as management
believes it provides additional information concerning the
performance of our business and is used by investors and financial
analysts to analyze and compare our current operating and financial
performance relative to past performance and such performances
relative to that of other publicly traded partnerships in the
industry. Adjusted EBITDA may not be comparable to similarly titled
measures of other publicly traded limited partnerships or limited
liability companies because all companies may not calculate such
measures in the same manner.
Certain factors impacting Adjusted EBITDA may be
viewed as temporary, one-time in nature, or being offset by
reserves from past performance or near-term future performance.
Financial results are also driven by various factors that do not
typically occur evenly throughout the year that are difficult to
predict, including rig availability, weather, well performance, the
timing of drilling and completions and near-term commodity price
changes. Consistent with practices common to publicly traded
partnerships, the board of directors of our general partner
historically has not varied the distribution it declares based on
such timing effects.
"Adjusted EBITDA" should not be considered as an
alternative to GAAP measures, such as net income, operating income,
cash flow from operating activities, or any other GAAP measure of
financial performance.
Adjusted EBITDA is defined as net income (loss)
plus:
- Interest expense;
- Income tax expense (benefit);
- (Gain) loss on extinguishment of debt
- Depletion, depreciation, amortization and accretion;
- Impairment of long-lived assets;
- (Gain) loss on sale of partnership investment;
- (Gain) loss on disposal of assets;
- Equity in (income) loss of equity method investees;
- Unit-based compensation expense (benefit) related to LTIP unit
awards accounted for under the equity or liability
methods;
- Minimum payments received in excess of overriding royalty
interest earned;
- Equity in EBITDA of equity method investee;
- Net (gains) losses on commodity derivatives;
- Net cash settlements received (paid) on commodity derivatives;
and
- Transaction related expenses.
The following table presents a reconciliation of
our consolidated net income (loss) to Adjusted EBITDA:
|
Three Months Ended |
|
Twelve Months Ended |
|
December 31, |
|
December 31, |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
|
(In thousands) |
Net
loss |
$ |
(104,585 |
) |
|
$ |
(344,136 |
) |
|
$ |
(55,820 |
) |
|
$ |
(701,541 |
) |
Plus: |
|
|
|
|
|
|
|
Interest
expense |
16,502 |
|
|
17,988 |
|
|
79,060 |
|
|
76,891 |
|
Gain on
debt extinguishment |
— |
|
|
— |
|
|
(150,802 |
) |
|
|
Income
tax expense (benefit) |
519 |
|
|
(1,208 |
) |
|
1,229 |
|
|
(1,498 |
) |
Depletion, depreciation, amortization and accretion |
39,719 |
|
|
54,952 |
|
|
150,414 |
|
|
177,258 |
|
Impairment of long-lived assets |
41,731 |
|
|
326,349 |
|
|
61,796 |
|
|
633,805 |
|
Gain on
disposal of assets |
(806 |
) |
|
(5,539 |
) |
|
(50,095 |
) |
|
(3,972 |
) |
Equity in
income of equity method investees |
(7 |
) |
|
(29 |
) |
|
— |
|
|
(126 |
) |
Unit-based compensation expense |
1,586 |
|
|
1,688 |
|
|
7,198 |
|
|
6,673 |
|
Minimum
payments received in excess of overriding royalty interest
earned(1) |
434 |
|
|
— |
|
|
1,659 |
|
|
1,130 |
|
Equity in
EBITDA of equity method investee(2) |
— |
|
|
— |
|
|
— |
|
|
169 |
|
Net
(gains) losses on commodity derivatives |
38,913 |
|
|
(34,270 |
) |
|
41,224 |
|
|
(98,253 |
) |
Net cash
settlements received on commodity derivatives |
8,022 |
|
|
28,612 |
|
|
64,505 |
|
|
132,925 |
|
Transaction related expenses |
4,158 |
|
|
743 |
|
|
5,245 |
|
|
8,919 |
|
Adjusted
EBITDA |
$ |
46,186 |
|
|
$ |
45,150 |
|
|
$ |
155,613 |
|
|
$ |
232,380 |
|
(1) Minimum payments received in excess of overriding royalties
earned under a contractual agreement expiring December 31, 2019.
The remaining amount of the minimum payments are recognized in net
income.
(2) EBITDA applicable to equity method investee is defined as
the equity method investee's net income or loss plus interest
expense and depreciation. We divested our interest in this investee
in May of 2015.
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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