Legacy Reserves LP ("Legacy") (NASDAQ:LGCY) today announced fourth
quarter and annual results for 2015. Financial results
contained herein are preliminary and subject to the audited
financial statements included in Legacy’s Form 10-K to be filed on
or about February 26, 2016.
A summary of selected financial information follows. For
consolidated financial statements, please see accompanying
tables.
|
|
Three Months Ended |
|
Twelve Months Ended |
|
|
December 31, |
|
December 31, |
|
|
2015 |
|
2014 |
|
2015 |
|
2014 |
|
|
(dollars in millions) |
Production (Boe/d) |
|
45,435 |
|
|
32,783 |
|
|
38,523 |
|
|
26,962 |
|
Revenue |
|
$ |
79.9 |
|
|
$ |
119.6 |
|
|
$ |
338.8 |
|
|
$ |
532.3 |
|
Net Loss (a) |
|
$ |
(344.1 |
) |
|
$ |
(331.5 |
) |
|
$ |
(701.5 |
) |
|
$ |
(283.6 |
) |
Adjusted EBITDA
(b) |
|
$ |
45.2 |
|
|
$ |
64.7 |
|
|
$ |
232.4 |
|
|
$ |
278.2 |
|
Distributable Cash Flow
(b) |
|
$ |
12.9 |
|
|
$ |
24.2 |
|
|
$ |
103.5 |
|
|
$ |
128.1 |
|
(a) Includes non-cash impairment charges of $326.3 million and
$440.1 million for the fourth quarter of 2015 and 2014,
respectively, and $633.8 million and $448.7 million for the years
ended December 31, 2015 and 2014, respectively.(b) Non-GAAP
financial measure. Please see Adjusted EBITDA and Distributable
Cash Flow table at the end of this press release for a
reconciliation of these measures to their nearest comparable GAAP
measure.
2015 highlights include:
- Completed $489.3 million of acquisitions, net of properties
immediately divested after acquisition
- Generated record annual production of 38,523 Boe/d up 43% from
26,962 Boe/d in 2014
- Reduced production expenses, excluding ad valorem taxes, by 2%
despite significant growth in our asset base
- Year-end proved reserves increased 18% to a record 164.2 MMBoe
(97% PDP, 27% liquids)
Paul T. Horne, President and Chief Executive Officer of Legacy's
general partner, commented, "Despite the challenging commodity
price environment in 2015, I’m exceedingly proud of our team’s
accomplishments this year. We knew coming into the year that,
should prices not improve, we were going to face significant
headwinds. However, in light of these challenges, we were able to
achieve several milestones. We made expense reduction a significant
goal in 2015 and were able to reduce production expenses to a level
below our 2014 costs, even when including recent acquisitions. From
Q4 2014 to Q4 2015, excluding the effect of any acquisitions made
during that time, we have reduced our production expenses
(excluding taxes) by just over 23% which, quite frankly, I did not
believe was possible. Our previously announced development
agreement with an affiliate of TPG Special Situation Partners
allowed us to monetize a portion of our undeveloped assets in the
Permian. We have drilled and completed six wells under the
agreement and are in the process of completing six more wells. Our
drilling costs have outperformed expectations and we anticipate
strong production results once all wells are completed. Our
acquisitions of natural gas properties and related gathering and
processing assets in East Texas have provided a significant entry
into a new basin as well as exposure to a new cash flow stream. Our
team has done a fantastic job integrating these assets and we look
forward to the opportunity to pursue some accretive capital
projects on these assets in 2016.
"We anticipate 2016 will be another challenging year. Commodity
prices have remained depressed and have further deteriorated our
cash-flow projections. As previously announced, we suspended
distributions to our unitholders and our preferred unitholders in
order to focus on our balance sheet, liquidity position and
leverage metrics. We continue to work through select
credit-accretive asset sales and other opportunities. As we have
stated in the past, we strongly believe that today’s current
commodity price environment is unsustainable and believe our
efforts in 2015 and our planned efforts in 2016 will best position
us to capitalize when a recovery occurs.”
Dan Westcott, Executive Vice President and Chief Financial
Officer of Legacy's general partner, commented, "Though low
commodity prices have persisted in our industry for the last 18
months, I’m proud of our results and efforts to date. We have been
taking difficult, but important steps to improve our balance sheet
position: cutting operation costs, suspending distributions and
initiating credit-accretive asset sales. We also recently amended
our revolving credit facility, providing greater flexibility under
certain covenants to better weather this storm. In particular, we
have modified our Secured Debt to EBITDA covenant to a 1st Lien
Debt to EBITDA covenant that begins at 3.5x and tapers to 2.5x by
Q3 2017 and have reduced our EBITDA to Interest Expense covenant to
2.0x beginning Q2 2016 through Q2 2017. As part of the amendment,
we reduced our borrowing base to $725 million leaving us with
$105.6 million of current availability. Based on current strip
prices, we project we are slightly free cash flow positive in 2016
and we have sufficient liquidity for the year. We plan to use any
asset sale proceeds to generate additional cash to reduce our total
debt outstanding and improve our financial metrics.”
Proved Reserves
The following information represents estimates of our proved
reserves as of December 31, 2015 which have been prepared in
compliance with the SEC rules and accounting standards using
current costs and the average annual prices based on the unweighted
arithmetic average of the first-day-of-the-month price for each
month in the year ending December 31, 2015. Our average WTI price,
as posted by Plains Marketing L.P., was $46.79 per Bbl for oil
and our average natural gas price, as posted by Platts Gas Daily,
was $2.59 per MMBtu. Our proved reserves by operating region
as of December 31, 2015 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized |
|
|
Oil |
|
Natural |
|
NGLs |
|
Total |
|
|
|
|
|
|
|
|
|
|
Measure |
Operating Regions |
|
(MBbls) |
|
Gas (MMcf) |
|
(MBbls) |
|
(MBoe) |
|
% Liquids |
|
% PDP |
|
% Total |
|
($ thousands)(1) |
Permian Basin |
|
28,111 |
|
|
100,414 |
|
|
1,091 |
|
|
45,938 |
|
|
63.6 |
% |
|
91.8 |
% |
|
28.0 |
% |
|
$ |
361,514 |
|
East Texas |
|
31 |
|
|
429,274 |
|
|
4 |
|
|
71,580 |
|
|
— |
% |
|
97.9 |
% |
|
43.6 |
% |
|
211,220 |
|
Rocky Mountain |
|
5,772 |
|
|
180,019 |
|
|
4,369 |
|
|
40,144 |
|
|
25.3 |
% |
|
98.8 |
% |
|
24.5 |
% |
|
87,710 |
|
Mid-Continent |
|
2,185 |
|
|
10,861 |
|
|
2,180 |
|
|
6,175 |
|
|
70.7 |
% |
|
99.8 |
% |
|
3.8 |
% |
|
33,284 |
|
Other |
|
44 |
|
|
1,065 |
|
|
107 |
|
|
329 |
|
|
45.9 |
% |
|
100.0 |
% |
|
0.1 |
% |
|
1,213 |
|
Total |
|
36,143 |
|
|
721,633 |
|
|
7,751 |
|
|
164,166 |
|
|
26.7 |
% |
|
96.5 |
% |
|
100.0 |
% |
|
$ |
694,941 |
|
(1) Standardized measure is the present value of
estimated future net revenues to be generated from the production
of proved reserves, determined in accordance with assumptions
required by the Financial Accounting Standards Board and the
Securities and Exchange Commission (using current costs and the
average annual prices based on the unweighted arithmetic average of
the first-day-of-the-month price) without giving effect to
non-property related expenses such as general administrative
expenses and debt service or to depletion, depreciation and
amortization and discounted using an annual discount rate of 10%.
For the purpose of calculating the standardized measure, the costs
and prices are unescalated. Federal income taxes have not been
deducted from future production revenues in the calculation of
standardized measure as each partner is separately taxed on its
share of Legacy's taxable income. In addition, Texas margin taxes
and the federal income taxes associated with a corporate subsidiary
have not been deducted from future production revenues in the
calculation of the standardized measure as the impact of these
taxes would not have a significant effect on the calculated
standardized measure. Standardized measure does not give effect to
derivative transactions.
2016 Capital Program By Category
|
|
Percent of Total |
|
|
|
Horizontal Permian
Drilling |
|
30 |
% |
East Texas (Workovers,
G&P, Facilities) |
|
30 |
% |
Other Workovers |
|
20 |
% |
CO2 + Other
Facilities |
|
20 |
% |
Total Capital
Expenditures |
|
100 |
% |
Total Capital
Expenditures Dollars |
|
$ |
37,000 |
|
We do not maintain any long-term drilling contracts and serve as
operator of approximately 90% of our anticipated capital program.
Accordingly, we maintain significant control of the capital program
budget and may deviate materially from the figures above based on
market condition (or otherwise) with the overriding intent to
deploy capital prudently. Should current commodity prices persist,
we may reduce our capital program meaningfully to further our
capital preservation efforts.
LEGACY RESERVES LP |
SELECTED FINANCIAL AND OPERATING
DATA |
|
|
Three Months Ended |
|
Twelve Months Ended |
|
December 31, |
|
December 31, |
|
2015 |
|
2014 |
|
2015 |
|
2014 |
|
(In thousands, except per unit
data) |
Revenues |
|
|
|
|
|
|
|
Oil sales |
$ |
40,653 |
|
|
$ |
80,348 |
|
|
$ |
199,841 |
|
|
$ |
396,774 |
|
Natural gas liquids sales |
3,778 |
|
|
8,002 |
|
|
16,645 |
|
|
27,483 |
|
Natural gas sales |
35,510 |
|
|
31,256 |
|
|
122,293 |
|
|
108,042 |
|
Total revenues |
$ |
79,941 |
|
|
$ |
119,606 |
|
|
$ |
338,779 |
|
|
$ |
532,299 |
|
Expenses: |
|
|
|
|
|
|
|
Oil and natural gas production |
$ |
48,436 |
|
|
$ |
53,222 |
|
|
$ |
183,163 |
|
|
$ |
186,750 |
|
Ad valorem taxes |
3,169 |
|
|
1,745 |
|
|
11,328 |
|
|
12,051 |
|
Total |
$ |
51,605 |
|
|
$ |
54,967 |
|
|
$ |
194,491 |
|
|
$ |
198,801 |
|
Production and other taxes |
$ |
3,345 |
|
|
$ |
7,242 |
|
|
$ |
16,383 |
|
|
$ |
31,534 |
|
General and administrative
excluding LTIP & acquisition costs |
$ |
8,574 |
|
|
$ |
8,164 |
|
|
$ |
30,919 |
|
|
$ |
29,760 |
|
Acquisition costs |
743 |
|
|
95 |
|
|
8,919 |
|
|
5,425 |
|
LTIP expense (benefit) |
1,689 |
|
|
(60 |
) |
|
6,673 |
|
|
3,795 |
|
Total general and
administrative |
$ |
11,006 |
|
|
$ |
8,199 |
|
|
$ |
46,511 |
|
|
$ |
38,980 |
|
Depletion, depreciation,
amortization and accretion |
$ |
54,952 |
|
|
$ |
53,436 |
|
|
$ |
177,258 |
|
|
$ |
173,686 |
|
Commodity derivative
cash settlements: |
|
|
|
|
|
|
|
Oil derivative cash settlements
received (paid) |
$ |
15,298 |
|
|
$ |
9,609 |
|
|
$ |
91,953 |
|
|
$ |
(5,431 |
) |
Natural gas derivative cash
settlements received |
13,314 |
|
|
5,031 |
|
|
40,972 |
|
|
8,097 |
|
Total commodity derivative cash
settlements |
$ |
28,612 |
|
|
$ |
14,640 |
|
|
$ |
132,925 |
|
|
$ |
2,666 |
|
Production: |
|
|
|
|
|
|
|
Oil (MBbls) |
1,088 |
|
|
1,253 |
|
|
4,608 |
|
|
4,784 |
|
Natural gas liquids (MGal) |
10,874 |
|
|
11,283 |
|
|
42,210 |
|
|
30,861 |
|
Natural gas (MMcf) |
16,997 |
|
|
8,966 |
|
|
50,687 |
|
|
25,936 |
|
Total (MBoe) |
4,180 |
|
|
3,016 |
|
|
14,061 |
|
|
9,841 |
|
Average daily production
(Boe/d) |
45,435 |
|
|
32,783 |
|
|
38,523 |
|
|
26,962 |
|
Average
sales price per unit (excluding commodity derivative cash
settlements): |
|
|
|
|
Oil price (per Bbl) |
$ |
37.36 |
|
|
$ |
64.12 |
|
|
$ |
43.37 |
|
|
$ |
82.94 |
|
Natural gas liquids price (per
Gal) |
$ |
0.35 |
|
|
$ |
0.71 |
|
|
$ |
0.39 |
|
|
$ |
0.89 |
|
Natural gas price (per Mcf)(a) |
$ |
2.09 |
|
|
$ |
3.49 |
|
|
$ |
2.41 |
|
|
$ |
4.17 |
|
Combined (per Boe) |
$ |
19.12 |
|
|
$ |
39.66 |
|
|
$ |
24.09 |
|
|
$ |
54.09 |
|
Average
sales price per unit (including commodity derivative cash
settlements): |
|
|
|
|
Oil price (per Bbl) |
$ |
51.43 |
|
|
$ |
71.79 |
|
|
$ |
63.32 |
|
|
$ |
81.80 |
|
Natural gas liquids price (per
Gal) |
$ |
0.35 |
|
|
$ |
0.71 |
|
|
$ |
0.39 |
|
|
$ |
0.89 |
|
Natural gas price (per Mcf)(a) |
$ |
2.87 |
|
|
$ |
4.05 |
|
|
$ |
3.22 |
|
|
$ |
4.48 |
|
Combined (per Boe) |
$ |
25.97 |
|
|
$ |
44.51 |
|
|
$ |
33.55 |
|
|
$ |
54.36 |
|
|
|
|
|
|
|
|
|
Average WTI oil spot
price (per Bbl) |
$ |
42.07 |
|
|
$ |
73.20 |
|
|
$ |
48.81 |
|
|
$ |
92.91 |
|
Average Henry Hub
natural gas index price (per Mcf) |
$ |
2.23 |
|
|
$ |
3.83 |
|
|
$ |
2.63 |
|
|
$ |
4.26 |
|
|
|
|
|
|
|
|
|
Average unit costs per
Boe: |
|
|
|
|
|
|
|
Production costs, excluding
production and other taxes |
$ |
11.59 |
|
|
$ |
17.65 |
|
|
$ |
13.03 |
|
|
$ |
18.98 |
|
Ad valorem taxes |
$ |
0.76 |
|
|
$ |
0.58 |
|
|
$ |
0.81 |
|
|
$ |
1.22 |
|
Production and other taxes |
$ |
0.80 |
|
|
$ |
2.40 |
|
|
$ |
1.17 |
|
|
$ |
3.20 |
|
General and administrative
excluding LTIP & acquisition costs |
$ |
2.05 |
|
|
$ |
2.71 |
|
|
$ |
2.20 |
|
|
$ |
3.02 |
|
Total general and
administrative. |
$ |
2.63 |
|
|
$ |
2.72 |
|
|
$ |
3.31 |
|
|
$ |
3.96 |
|
Depletion, depreciation,
amortization and accretion. |
$ |
13.15 |
|
|
$ |
17.72 |
|
|
$ |
12.61 |
|
|
$ |
17.65 |
|
Annual Financial and Operating Results - 2015 Compared
to 2014
- Production increased 43% to an annual record of 38,523 Boe/d
from 26,962 Boe/d primarily due to $540.3 million of acquisitions
in 2015 including our acquisition of various oil and natural gas
properties and associated production assets from Anadarko E&P
Onshore LLC ("Anadarko Acquisition") for a net purchase price of
$335.5 million.
- Average realized price, excluding net cash settlements from
commodity derivatives, decreased 55% to $24.09 per Boe in 2015 from
$54.09 per Boe in 2014. Average realized oil price decreased 48% to
$43.37 in 2015 from $82.94 in 2014. This decrease was primarily
driven by a decrease in the average West Texas Intermediate ("WTI")
crude oil price of $44.10 per Bbl partially offset by a decrease in
realized differentials, primarily in the Permian Basin. Average
natural gas price decreased 42% to $2.41 per Mcf in 2015 from $4.17
per Mcf in 2014. This decrease was primarily driven by a decrease
in the average Henry Hub natural gas index price of $1.63 per Mcf.
Finally, our average realized NGL price decreased 56% to $0.39 per
gallon in 2015 from $0.89 per gallon in 2014.
- Production expenses, excluding ad valorem taxes, decreased 2%
to $183.2 million in 2015 from $186.8 million in 2014 due to our
cost containment efforts on our base assets, partially offset by
costs associated with the Anadarko Acquisition and other recent
acquisitions, as well as a full year of production costs on the
properties acquired from WPX in June 2014. On an average cost per
Boe basis, production expenses decreased 31% to $13.03 per Boe in
2015 from $18.98 per Boe in 2014, driven primarily by the inclusion
of lower cost natural gas properties from the Anadarko and WPX
acquisitions as well as a reduction in the production expenses from
our base assets.
- Non-cash impairment expense totaled $633.8 million driven by
the significant decline in oil and natural gas prices during
2015.
- General and administrative expenses, excluding acquisition
costs and unit-based Long-Term Incentive Plan ("LTIP") compensation
expense totaled $30.9 million in 2015 compared to $29.8 million in
2014. This increase was primarily attributable to a $1.9 million
increase in salary and benefit expenses, net of overhead recovery,
due to the hiring of 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
2015 were $132.9 million as compared to $2.7 million in 2014.
- Total development capital expenditures decreased to $36.8
million in 2015 from $133.4 million in 2014. During 2015 we entered
into a Development Agreement (the "Development Agreement") with
Jupiter JV, LP ("Investor"), which was formed by certain of TPG
Special Situations Partners' investment funds. Under the
Development Agreement, we drilled and completed 6 wells in 2015 and
had another 6 wells in process at December 31, 2015. During 2015 we
also incurred capital costs related to our CO2 injection on
properties acquired during 2014. Our non-operated capital
expenditures were 22% of our total capital expenditures in 2015 as
compared to 28% in 2014.
Financial and Operating Results - Fourth Quarter 2015
Compared to Fourth Quarter 2014
- Production increased 39% to 45,435 Boe/d from 32,783 Boe/d
primarily due to the Anadarko Acquisition and other recent
acquisitions.
- Average realized price, excluding net cash settlements from
commodity derivatives, decreased 52% to $19.12 per Boe in 2015 from
$39.66 per Boe in 2014. Average realized oil price decreased 42% to
$37.36 per Bbl in 2015 from $64.12 per Bbl in 2014. This decrease
of $26.76 was primarily attributable to the sharp decline in the
average WTI crude oil price of $31.13 partially offset by lower
realized regional differentials. Average realized natural gas
prices declined 40% to $2.09 per Mcf in 2015 from $3.49 per Mcf in
2014. This decrease of $1.40 was primarily attributable to a $1.60
decline in the average Henry Hub natural gas price index partially
offset by lower realized regional differentials. Finally, our
average realized NGL price decreased 51% to $0.35 per gallon in
2015 from $0.71 per gallon in 2014.
- Production expenses, excluding ad valorem taxes, decreased 9%
to $48.4 million in 2015 from $53.2 million in 2014. Production
expenses decreased primarily due to cost reduction efforts on our
historical properties partially offset by additional expenses on
properties acquired in 2015. On a per Boe basis, production
expenses decreased to $11.59 from $17.65 or 34% driven by
acquisitions of properties with lower per Boe production expenses
as well as cost reductions in our ongoing operations.
- Non-cash impairment expense totaled $326.3 million due to the
significant decline of oil and natural gas prices during the
period.
- General and administrative expenses, excluding acquisition
costs and LTIP compensation expense, increased to $8.6 million in
2015 from $8.2 million in 2014. This increase was primarily
attributable to an increase in salary and benefit expenses related
to the hiring of additional personnel to manage our larger asset
base partially offset by general cost reduction efforts.
- Cash settlements received on our commodity derivatives were
$28.6 million during 2015 compared to $14.6 million in 2014,
resulting from the continued decline in commodity prices during
2015.
- Total development capital expenditures were $7.2 million in the
fourth quarter of 2015. Non-operated capital expenditures comprised
13% of our total capital expenditures during the period with
activity primarily in the Permian.
Commodity Derivative Contracts
We enter into oil and natural gas derivative contracts to help
mitigate the risk of changing commodity prices. As of February 22,
2016, we had entered into derivative agreements to receive average
NYMEX WTI crude oil prices and NYMEX Henry Hub, Waha, 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 |
2016 |
|
594,600 |
|
|
$ |
68.37 |
|
|
$ |
56.15 |
|
- |
$ |
99.85 |
|
2017 |
|
182,500 |
|
|
$ |
84.75 |
|
|
$ |
84.75 |
|
WTI Crude Oil 3-Way Collars. As an illustrative example, at an
annual average WTI market price of $35.00, the summary positions
below would result in a net price of $60.00 for both 2016 and
2017.
|
|
|
|
Average Short Put |
|
Average Long Put |
|
Average Short Call |
Calendar Year |
|
Volumes (Bbls) |
|
Price per Bbl |
|
Price per Bbl |
|
Price per Bbl |
2016 |
|
621,300 |
|
|
$ |
63.37 |
|
|
$ |
88.37 |
|
|
$ |
106.40 |
|
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 $35.00, the summary positions
below would result in a net price of $66.70, $65.85 and $65.50, for
2016, 2017 and 2018, respectively.
|
|
|
|
Average Long Put |
|
Average Short Put |
|
Average Swap |
Calendar Year |
|
Volumes (Bbls) |
|
Price per Bbl |
|
Price per Bbl |
|
Price per Bbl |
2016 |
|
183,000 |
|
|
$ |
57.00 |
|
|
$ |
82.00 |
|
|
$ |
91.70 |
|
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 |
2016 |
|
2,928,000 |
|
|
$ |
(1.60 |
) |
|
$ |
(1.50 |
) |
- |
$ |
(1.75 |
) |
2017 |
|
2,190,000 |
|
|
$ |
(0.30 |
) |
|
$ |
(0.05 |
) |
- |
$ |
(0.75 |
) |
Natural Gas Swaps (Henry Hub, Waha and CIG-Rockies):
|
|
|
|
Average |
|
|
|
|
Calendar Year |
|
Volumes (MMBtu) |
|
Price per MMBtu |
|
Price Range per MMBtu |
2016 |
|
29,019,200 |
|
|
$ |
3.40 |
|
|
$ |
3.29 |
|
- |
$ |
5.30 |
|
2017 |
|
27,600,000 |
|
|
$ |
3.36 |
|
|
$ |
3.29 |
|
- |
$ |
3.39 |
|
2018 |
|
27,600,000 |
|
|
$ |
3.36 |
|
|
$ |
3.29 |
|
- |
$ |
3.39 |
|
2019 |
|
25,800,000 |
|
|
$ |
3.36 |
|
|
$ |
3.29 |
|
- |
$ |
3.39 |
|
Natural Gas 3-Way Collars (Henry Hub). As an illustrative
example, at an annual average Henry Hub market price of $2.50, the
summary positions below would result in a net price of $3.00 for
both 2016 and 2017.
|
|
Volumes |
|
Average Short Put |
|
Average Long Put |
|
Average Short Call |
Calendar Year |
|
(MMBtu) |
|
Price per MMBtu |
|
Price per MMBtu |
|
Price per MMBtu |
2016 |
|
5,580,000 |
|
$ |
3.75 |
|
|
$ |
4.25 |
|
|
$ |
5.08 |
|
2017 |
|
5,040,000 |
|
$ |
3.75 |
|
|
$ |
4.25 |
|
|
$ |
5.53 |
|
Natural Gas Basis Swaps (NWPL, SoCal and San Juan):
|
|
2016 |
|
2017 |
|
|
|
|
Average |
|
|
|
Average |
|
|
Volumes (MMBtu) |
|
Price per MMBtu |
|
Volumes (MMBtu) |
|
Price per MMBtu |
NWPL |
|
14,977,818 |
|
|
$ |
(0.19 |
) |
|
7,300,000 |
|
$ |
(0.16 |
) |
SoCal |
|
— |
|
|
$ |
— |
|
|
2,500,250 |
|
$ |
0.11 |
|
San Juan |
|
2,499,780 |
|
|
$ |
(0.16 |
) |
|
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 2015 Form 10-K which will
be filed on or about February 26, 2016.
Conference Call
As announced on January 21, 2016, Legacy will host an investor
conference call to discuss Legacy's results on Thursday, February
25, 2016 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 3, 2016, by dialing
855-859-2056 or 404-537-3406 and entering replay code 22745604.
Those wishing to listen to the live or archived web cast 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 unitholders, just like unitholders of other master
limited partnerships, are allocated taxable income irrespective of
cash distributions paid.
This release is intended to be a qualified notice under Treasury
Regulation Section 1.1446-4(b). Brokers and nominees should treat
one hundred percent (100.0%) of Legacy's distributions to foreign
investors as being attributable to income that is effectively
connected with a United States trade or business. Accordingly,
Legacy's distributions to foreign investors are subject to federal
income tax withholding at the highest applicable rate.
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 |
|
Twelve Months Ended |
|
December 31, |
|
December 31, |
|
2015 |
|
2014 |
|
2015 |
|
2014 |
|
(In thousands, except per unit
data) |
Revenues: |
|
|
|
|
|
|
|
Oil sales |
$ |
40,653 |
|
|
$ |
80,348 |
|
|
$ |
199,841 |
|
|
$ |
396,774 |
|
Natural gas liquids (NGL)
sales |
3,778 |
|
|
8,002 |
|
|
16,645 |
|
|
27,483 |
|
Natural gas sales |
35,510 |
|
|
31,256 |
|
|
122,293 |
|
|
108,042 |
|
Total revenues |
79,941 |
|
|
119,606 |
|
|
338,779 |
|
|
532,299 |
|
Expenses: |
|
|
|
|
|
|
|
Oil and natural gas production |
51,605 |
|
|
54,967 |
|
|
194,491 |
|
|
198,801 |
|
Production and other taxes |
3,345 |
|
|
7,242 |
|
|
16,383 |
|
|
31,534 |
|
General and administrative |
11,006 |
|
|
8,199 |
|
|
46,511 |
|
|
38,980 |
|
Depletion, depreciation,
amortization and accretion |
54,952 |
|
|
53,436 |
|
|
177,258 |
|
|
173,686 |
|
Impairment of long-lived
assets |
326,349 |
|
|
440,130 |
|
|
633,805 |
|
|
448,714 |
|
(Gain) loss on disposal of
assets |
(5,539 |
) |
|
756 |
|
|
(3,972 |
) |
|
(2,479 |
) |
Total expenses |
441,718 |
|
|
564,730 |
|
|
1,064,476 |
|
|
889,236 |
|
Operating income (loss) |
(361,777 |
) |
|
(445,124 |
) |
|
(725,697 |
) |
|
(356,937 |
) |
Other income
(expense): |
|
|
|
|
|
|
|
Interest income |
2 |
|
|
211 |
|
|
329 |
|
|
873 |
|
Interest expense |
(17,988 |
) |
|
(17,971 |
) |
|
(76,891 |
) |
|
(67,218 |
) |
Equity in income of equity method
investees |
29 |
|
|
119 |
|
|
126 |
|
|
428 |
|
Net gains (losses) on commodity
derivatives |
34,270 |
|
|
129,417 |
|
|
98,253 |
|
|
138,092 |
|
Other |
120 |
|
|
120 |
|
|
841 |
|
|
258 |
|
Income (loss) before income
taxes |
(345,344 |
) |
|
(333,228 |
) |
|
(703,039 |
) |
|
(284,504 |
) |
Income tax (expense)
benefit |
1,208 |
|
|
1,729 |
|
|
1,498 |
|
|
859 |
|
Net income (loss) |
$ |
(344,136 |
) |
|
$ |
(331,499 |
) |
|
$ |
(701,541 |
) |
|
$ |
(283,645 |
) |
Distributions to preferred
unitholders |
(4,750 |
) |
|
(4,750 |
) |
|
(19,000 |
) |
|
(11,694 |
) |
Net income (loss) attributable to
unitholders |
$ |
(348,886 |
) |
|
$ |
(336,249 |
) |
|
$ |
(720,541 |
) |
|
$ |
(295,339 |
) |
Income (loss) per unit — basic and
diluted |
$ |
(5.06 |
) |
|
$ |
(4.94 |
) |
|
$ |
(10.45 |
) |
|
$ |
(4.92 |
) |
Weighted average number of units
used in |
|
|
|
|
|
|
|
computing income (loss) per unit
— |
|
|
|
|
|
|
|
Basic |
68,950 |
|
|
68,035 |
|
|
68,928 |
|
|
60,053 |
|
Diluted |
68,950 |
|
|
68,035 |
|
|
68,928 |
|
|
60,053 |
|
LEGACY RESERVES LP |
CONDENSED CONSOLIDATED BALANCE
SHEETS |
(UNAUDITED) |
|
|
December 31, |
|
2015 |
|
2014 |
|
(In thousands) |
ASSETS |
Current assets: |
|
|
|
Cash |
$ |
2,006 |
|
|
$ |
725 |
|
Accounts receivable, net: |
|
|
|
Oil and natural gas |
33,944 |
|
|
49,390 |
|
Joint interest owners |
25,378 |
|
|
16,235 |
|
Other |
86 |
|
|
237 |
|
Fair value of derivatives |
63,711 |
|
|
120,305 |
|
Prepaid expenses and other current
assets |
4,334 |
|
|
5,362 |
|
Total current assets |
129,459 |
|
|
192,254 |
|
Oil and natural gas
properties, at cost: |
|
|
|
Proved oil and natural gas
properties using the successful efforts method of accounting |
3,485,634 |
|
|
2,946,820 |
|
Unproved properties |
13,424 |
|
|
47,613 |
|
Accumulated depletion,
depreciation, amortization and impairment |
(2,090,102 |
) |
|
(1,354,459 |
) |
|
1,408,956 |
|
|
1,639,974 |
|
Other property and
equipment, net of accumulated depreciation and amortization
of $8,915 and $7,446, respectively |
4,575 |
|
|
3,767 |
|
Operating rights, net
of amortization of $4,953 and $4,509, respectively |
2,064 |
|
|
2,508 |
|
Fair value of
derivatives |
56,373 |
|
|
32,794 |
|
Other assets, net of
amortization of $15,563 and $12,551, respectively |
23,829 |
|
|
24,255 |
|
Investments in equity
method investees |
646 |
|
|
3,054 |
|
Total assets |
$ |
1,625,902 |
|
|
$ |
1,898,606 |
|
LIABILITIES AND PARTNERS’ EQUITY |
Current
liabilities: |
|
|
|
Accounts payable |
$ |
13,581 |
|
|
$ |
2,787 |
|
Accrued oil and natural gas
liabilities |
50,573 |
|
|
78,615 |
|
Fair value of derivatives |
2,019 |
|
|
2,080 |
|
Asset retirement obligation |
3,496 |
|
|
3,028 |
|
Other |
11,424 |
|
|
11,066 |
|
Total current liabilities |
81,093 |
|
|
97,576 |
|
Long-term debt |
1,440,396 |
|
|
938,876 |
|
Asset retirement
obligation |
282,909 |
|
|
223,497 |
|
Fair value of
derivatives |
— |
|
|
— |
|
Other long-term
liabilities |
1,181 |
|
|
1,452 |
|
Total liabilities |
1,805,579 |
|
|
1,261,401 |
|
Commitments and
contingencies |
|
|
|
Partners’ equity: |
|
|
|
Series A Preferred equity -
2,300,000 units issued and outstanding at December 31, 2015 and
December 31, 2014 |
55,192 |
|
|
55,192 |
|
Series B Preferred equity -
7,200,000 units issued and outstanding at December 31, 2015 and
December 31, 2014 |
174,261 |
|
|
174,261 |
|
Incentive distribution equity -
100,000 units issued and outstanding at December 31, 2015 and
December 31, 2014 |
30,814 |
|
|
30,814 |
|
Limited partners' equity (deficit)
- 68,949,961 and 68,910,784 units issued and outstanding at
December 31, 2015 and 2014, respectively |
(439,811 |
) |
|
376,885 |
|
General partner’s equity (deficit)
(approximately 0.03%) |
(133 |
) |
|
53 |
|
Total partners’ equity |
(179,677 |
) |
|
637,205 |
|
Total liabilities and partners’
equity |
$ |
1,625,902 |
|
|
$ |
1,898,606 |
|
Non-GAAP Financial Measures
This press release, the financial tables and other supplemental
information include "Adjusted EBITDA" and "Distributable Cash
Flow", both of which are non-generally accepted accounting
principles ("non-GAAP") measures which may be used periodically by
management when discussing our financial results with investors and
analysts. The following presents a reconciliation of each of these
non-GAAP financial measures to their nearest comparable generally
accepted accounting principles ("GAAP") measure.
Adjusted EBITDA and Distributable Cash Flow are presented as
management believes they provide additional information concerning
the performance of our business and are 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 and Distributable Cash Flow 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.
Distributable Cash Flow is one of the factors used by the board
of directors of our general partner (the “Board”) to help determine
the amount of Available Cash as defined in our partnership
agreement, that is to be distributed to our unitholders for such
period. Under our partnership agreement, Available Cash is defined
generally to mean, cash on hand at the end of each quarter, plus
working capital borrowings made after the end of the quarter, less
cash reserves determined by our general partner. The Board
determines whether to increase, maintain or decrease the current
level of distributions in accordance with the provisions of our
partnership agreement based on a variety of factors, including
without limitation, Distributable Cash Flow, cash reserves
established in prior periods, reserves established for future
periods, borrowing capacity for working capital, temporary,
one-time or uncharacteristic historical results, and forecasts of
future period results including the impact of pending acquisitions.
Management and the Board consider the long-term view of expected
results in determining the amount of its distributions. Certain
factors impacting Adjusted EBITDA and Distributable Cash Flow 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 historically has not varied the
distribution it declares based on such timing effects.
"Adjusted EBITDA" and "Distributable Cash Flow" should not be
considered as alternatives 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 taxes;
- 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.
Distributable Cash Flow is defined as Adjusted EBITDA less:
- Cash interest expense including the accrual of interest expense
related to our senior notes which is paid on a semi-annual
basis;
- Cash income taxes;
- Cash settlements of LTIP unit awards;
- Estimated maintenance capital expenditures; and
- Distributions on Series A and Series B preferred units.
The following table presents a reconciliation of our
consolidated net income (loss) to Adjusted EBITDA and Distributable
Cash Flow:
|
Three Months Ended |
|
Twelve Months Ended |
|
December 31, |
|
December 31, |
|
2015 |
|
2014 |
|
2015 |
|
2014 |
|
(In thousands) |
Net
loss |
$ |
(344,136 |
) |
|
$ |
(331,499 |
) |
|
$ |
(701,541 |
) |
|
$ |
(283,645 |
) |
Plus: |
|
|
|
|
|
|
|
Interest expense |
17,988 |
|
|
17,971 |
|
|
76,891 |
|
|
67,218 |
|
Income tax expense (benefit) |
(1,208 |
) |
|
(1,729 |
) |
|
(1,498 |
) |
|
(859 |
) |
Depletion, depreciation,
amortization and accretion |
54,952 |
|
|
53,436 |
|
|
177,258 |
|
|
173,686 |
|
Impairment of long-lived
assets |
326,349 |
|
|
440,130 |
|
|
633,805 |
|
|
448,714 |
|
(Gain) loss on disposal of
assets |
(5,539 |
) |
|
756 |
|
|
(3,972 |
) |
|
(2,479 |
) |
Equity in income of equity method
investees |
(29 |
) |
|
(119 |
) |
|
(126 |
) |
|
(428 |
) |
Unit-based compensation expense
(benefit) |
1,688 |
|
|
(60 |
) |
|
6,673 |
|
|
3,795 |
|
Minimum payments received in excess
of overriding royalty interest earned(1) |
— |
|
|
358 |
|
|
1,130 |
|
|
1,381 |
|
Equity in EBITDA of equity method
investee(2) |
— |
|
|
156 |
|
|
169 |
|
|
805 |
|
Net gains on commodity
derivatives |
(34,270 |
) |
|
(129,417 |
) |
|
(98,253 |
) |
|
(138,092 |
) |
Net cash settlements received on
commodity derivatives |
28,612 |
|
|
14,640 |
|
|
132,925 |
|
|
2,666 |
|
Transaction related expenses |
743 |
|
|
95 |
|
|
8,919 |
|
|
5,425 |
|
Adjusted
EBITDA |
$ |
45,150 |
|
|
$ |
64,718 |
|
|
$ |
232,380 |
|
|
$ |
278,187 |
|
|
|
|
|
|
|
|
|
Less: |
|
|
|
|
|
|
|
Cash interest expense |
20,295 |
|
|
17,597 |
|
|
72,919 |
|
|
65,236 |
|
Cash settlements of LTIP unit
awards |
— |
|
|
1 |
|
|
— |
|
|
772 |
|
Estimated maintenance capital
expenditures(3) |
|
NM* |
|
|
18,200 |
|
|
|
NM* |
|
|
72,400 |
|
Development capital
expenditures(4) |
7,179 |
|
|
NM* |
|
36,842 |
|
|
NM* |
Distributions on Series A and
Series B preferred units |
4,750 |
|
|
4,750 |
|
|
19,000 |
|
|
11,694 |
|
Distributable
Cash Flow(3) |
$ |
12,926 |
|
|
$ |
24,170 |
|
|
$ |
103,619 |
|
|
$ |
128,085 |
|
|
|
|
|
|
|
|
|
Distributions
Attributable to Each Period(5) |
$ |
— |
|
|
$ |
42,208 |
|
|
$ |
58,957 |
|
|
$ |
153,829 |
|
|
|
|
|
|
|
|
|
Distribution
Coverage Ratio(3)(6) |
|
N/A |
|
|
0.57x |
|
1.76x |
|
0.83x |
(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.
(3) Estimated maintenance capital expenditures are intended to
represent the amount of capital required to fully offset declines
in production, but do not target specific levels of proved reserves
to be achieved. Estimated maintenance capital expenditures do not
include the cost of new oil and natural gas reserve acquisitions,
but rather the costs associated with converting proved developed
non-producing, proved undeveloped and unproved reserves to proved
developed producing reserves. These costs, which are incorporated
in our annual capital budget as approved by the Board, include
development drilling, recompletions, workovers and various other
procedures to generate new or improve existing production on both
operated and non-operated properties. Estimated maintenance capital
expenditures are based on management's judgment of various factors
including the long-term (generally 5-10 years) decline rate of our
current production and the projected productivity of our total
development capital expenditures. Actual production decline
rates and capital efficiency may materially differ from our
projections and such estimated maintenance capital expenditures may
not maintain our production. Further, because estimated maintenance
capital expenditures are not intended to target specific levels of
reserves, if we do not acquire new proved or unproved reserves, our
total reserves will decrease over time and we would be unable to
sustain production at current levels, which could adversely affect
our ability to pay a distribution at the current level or at
all.
(4) Represents total capital expenditures for the development of
oil and natural gas properties as presented on an accrual basis.
For 2016, we intend to fund our total oil and natural gas
development program from net cash provided by operating activities.
Previously, we intended to fund only a portion of our oil and
natural gas development program from net cash provided by operating
activities.
(5) Represents the aggregate cash distributions declared for the
respective period and paid by Legacy to our unitholders within 45
days after the end of each quarter within such period.
(6) We refer to the ratio of Distributable Cash Flow over
Distributions Attributable to Each Period ("Available Cash"
available for distribution to our unitholders per our partnership
agreement) as "Distribution Coverage Ratio." If the Distribution
Coverage Ratio is equal to or greater than 1.0x, then our cash
flows are sufficient to cover our quarterly distributions to our
unitholders with respect to such period. If the Distribution
Coverage Ratio is less than 1.0x, then our cash flows with respect
to such period were not sufficient to cover our quarterly
distributions to our unitholders and we must borrow funds or use
cash reserves established in prior periods to cover our quarterly
distributions to our unitholders. The Board uses its
discretion in determining if such shortfalls are temporary or if
distributions should be adjusted downward.
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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