Legacy Reserves LP ("Legacy") (NASDAQ:LGCY) today announced third
quarter results for 2015.
Q3 highlights include:
- Record production of 41,152 Boe/d
- Lease operating expense (excluding ad valorem taxes) of $46.0
million, a $0.5 million (1.1%) improvement relative to Q2 2015 and
a $10.9 million (20.4%) improvement relative to Q4 2014 when
excluding the impact of recent acquisitions
- Adjusted EBITDA of $55.3 million on a net loss of $90.1
million
- Distributable Cash Flow of $24.1 million, covering our new
$0.15 per unit quarterly distribution by 2.31 times
Paul T. Horne, President and Chief Executive Officer of Legacy
commented, "Despite the commodity price headwind, the third quarter
was a very productive quarter for Legacy. During the quarter we
closed on approximately $476 million of acquisitions of East Texas
properties, and have onboarded over 60 people to cover these
assets. We are currently working on improving field processes and
believe we have several accretive projects available to us in this
area. Additionally, we are currently running two drilling rigs
under our Development Agreement with TPG Special Situations
Partners and are pleased with our early results. We continue to
focus on the areas of our business that we can control and are glad
to see our production costs decline further in the third quarter.
Our team's ability to drive down costs while holding production
flat is absolutely spectacular."
Dan Westcott, Executive Vice President and Chief Financial
Officer of Legacy commented, "We had a good quarter, especially in
light of the current industry environment. As we previously
announced, we have reduced our annualized distribution to $0.60 per
unit from $1.40 per unit. While we generated more than adequate
coverage this quarter to pay our previous distribution amount, we
made the difficult decision to prioritize our focus on our balance
sheet. As we recently stated, we do not believe the current
commodity prices are sustainable and believe it is in our
unitholders' best interest for us to turn greater attention to our
balance sheet so that we can be best positioned when commodity
prices recover. We currently have approximately $343 million of
availability under our $950 million borrowing base which provides
more than ample headroom to run our business. We expect to complete
our fall redetermination in the coming weeks and expect only a
modest reduction to our current borrowing base."
LEGACY RESERVES
LP |
SELECTED FINANCIAL AND
OPERATING DATA |
|
Three Months
Ended |
Nine Months
Ended |
|
September 30, |
September 30, |
|
2015 |
2014 |
2015 |
2014 |
|
(In thousands, except
per unit data) |
Revenues: |
|
|
|
|
Oil sales |
$ 49,779 |
$ 105,640 |
$ 159,188 |
$ 316,426 |
Natural gas liquids sales |
2,946 |
10,413 |
12,867 |
19,482 |
Natural gas sales |
36,773 |
33,623 |
86,783 |
76,786 |
Total revenue |
$ 89,498 |
$ 149,676 |
$ 258,838 |
$ 412,694 |
Expenses: |
|
|
|
|
Oil and natural gas production,
excluding ad valorem taxes |
$ 45,954 |
$ 51,835 |
$ 134,727 |
$ 133,528 |
Ad valorem taxes |
$ 2,492 |
$ 3,656 |
$ 8,160 |
$ 10,306 |
Total oil and
natural gas production |
$ 48,446 |
$ 55,491 |
$ 142,887 |
$ 143,834 |
Production and other taxes |
$ 4,834 |
$ 7,742 |
$ 13,038 |
$ 24,292 |
General and administrative,
excluding acq. costs and LTIP |
$ 8,040 |
$ 6,936 |
$ 22,345 |
$ 21,596 |
Acquisition costs |
$ 6,502 |
$ 364 |
$ 8,176 |
$ 5,330 |
LTIP expense |
$ 1,704 |
$ 1,025 |
$ 4,985 |
$ 3,855 |
Total general and
administrative |
$ 16,246 |
$ 8,325 |
$ 35,506 |
$ 30,781 |
Depletion, depreciation,
amortization and accretion |
$ 45,041 |
$ 48,016 |
$ 122,306 |
$ 120,250 |
Commodity derivative cash settlements: |
|
|
|
|
Oil derivative cash settlements
received (paid) |
$ 17,092 |
$ (6,239) |
$ 76,656 |
$ (15,039) |
Natural gas derivative cash
settlements received |
$ 9,696 |
$ 3,885 |
$ 27,658 |
$ 3,065 |
Production: |
|
|
|
|
Oil (MBbls) |
1,149 |
1,221 |
3,520 |
3,532 |
Natural gas liquids (MGal) |
10,084 |
10,697 |
31,336 |
19,578 |
Natural gas (MMcf) |
14,383 |
8,867 |
33,689 |
16,970 |
Total (MBoe) |
3,786 |
2,954 |
9,881 |
6,826 |
Average daily production
(Boe/d) |
41,152 |
32,109 |
36,194 |
25,004 |
Average sales price per unit (excluding
derivative cash settlements): |
|
|
|
|
Oil price (per Bbl) |
$ 43.32 |
$ 86.52 |
$ 45.22 |
$ 89.59 |
Natural gas liquids price (per
Gal) |
$ 0.29 |
$ 0.97 |
$ 0.41 |
$ 1.00 |
Natural gas price (per
Mcf) |
$ 2.56 |
$ 3.79 |
$ 2.58 |
$ 4.52 |
Combined (per Boe) |
$ 23.64 |
$ 50.67 |
$ 26.20 |
$ 60.46 |
Average sales price per unit (including
derivative cash settlements): |
|
|
|
|
Oil price (per Bbl) |
$ 58.20 |
$ 81.41 |
$ 67.00 |
$ 85.33 |
Natural gas liquids price (per
Gal) |
$ 0.29 |
$ 0.97 |
$ 0.41 |
$ 1.00 |
Natural gas price (per
Mcf) |
$ 3.23 |
$ 4.23 |
$ 3.40 |
$ 4.71 |
Combined (per Boe) |
$ 30.71 |
$ 49.87 |
$ 36.75 |
$ 58.70 |
Average WTI oil spot price (per Bbl) |
$ 46.41 |
$ 97.25 |
$ 51.00 |
$ 99.62 |
Average Henry Hub natural gas index price
(per Mcf) |
$ 2.73 |
$ 3.95 |
$ 2.76 |
$ 4.41 |
Average unit costs per Boe: |
|
|
|
|
Oil and natural gas
production |
$ 12.14 |
$ 17.55 |
$ 13.63 |
$ 19.56 |
Ad valorem taxes |
$ 0.66 |
$ 1.24 |
$ 0.83 |
$ 1.51 |
Production and other taxes |
$ 1.28 |
$ 2.62 |
$ 1.32 |
$ 3.56 |
General and administrative
excluding acq. costs and LTIP |
$ 2.12 |
$ 2.35 |
$ 2.26 |
$ 3.16 |
Total general and
administrative |
$ 4.29 |
$ 2.82 |
$ 3.59 |
$ 4.51 |
Depletion, depreciation,
amortization and accretion |
$ 11.90 |
$ 16.25 |
$ 12.38 |
$ 17.62 |
Financial and Operating Results - Three-Month Period
Ended September 30, 2015 Compared to Three-Month Period Ended
September 30, 2014
- Production increased 28% to 41,152 Boe/d from 32,109 Boe/d
primarily due to our 2015 acquisitions including our East Texas
acquisitions from WGR Operating LP and Anadarko E&P Onshore LLC
("Anadarko Acquisitions").
- Average realized price, excluding net cash settlements from
commodity derivatives, decreased 53% to $23.64 per Boe in 2015 from
$50.67 per Boe in 2014 driven by the significant decline in
commodity prices as well as the increase of NGL and natural gas
production as a percentage of total production. Average realized
oil price decreased 50% to $43.32 in 2015 from $86.52 in 2014
driven by a decrease in the average West Texas Intermediate ("WTI")
crude oil price of $50.84 per Bbl partially offset by a decrease in
realized regional differentials. Average realized natural gas price
decreased 32% to $2.56 per Mcf in 2015 from $3.79 per Mcf in 2014.
This decrease is a result of the decrease in the average Henry Hub
natural gas index price of $1.22 per Mcf. Finally, our average
realized NGL price decreased 70% to $0.29 per gallon in 2015 from
$0.97 per gallon in 2014.
- Production expenses, excluding ad valorem taxes, decreased 11%
to $46.0 million in 2015 from $51.8 million in 2014. On an average
cost per Boe basis, production expenses decreased 31% to $12.14 per
Boe in 2015 from $17.55 per Boe in 2014, driven primarily by
expense reduction efforts across the properties that we have owned
prior to the Anadarko Acquisitions as well as the inclusion of
lower cost natural gas properties acquired in the Anadarko
Acquisitions.
- General and administrative expenses, excluding unit-based
Long-Term Incentive Plan ("LTIP") compensation expense totaled
$14.5 million in 2015 compared to $7.3 million in 2014. This
increase was primarily due to a $6.1 million increase in
acquisition costs between the periods as we incurred approximately
$6.5 million of one-time acquisition-related expenses during the
third quarter of 2015 associated with the Anadarko Acquisitions and
an advisory fee related to the establishment of a Development
Agreement with Jupiter JV, LP, which was formed by certain of TPG
Special Situations Partners' investment funds to participate in the
funding, exploration, development and operation of certain of our
currently undeveloped oil and gas properties.
- Cash settlements received on our commodity derivatives during
2015 were $26.8 million compared to cash settlements paid of
approximately $2.4 million in 2014.
- Total development capital expenditures decreased to $7.9
million in 2015 from $33.5 million in 2014. The 2015 activity was
comprised mainly of the drilling and completion of two non-operated
horizontal wells and capital costs related to CO2 properties.
- Non-cash impairment expense totaled $98.1 million due to the
continued decline in oil and natural gas futures prices.
Financial and Operating Results - Nine-Month Period
Ended September 30, 2015 Compared to Nine-Month Period Ended
September 30, 2014
- Production increased 45% to 36,194 Boe/d from 25,004 Boe/d
primarily due to acquisitions in 2015 including the Anadarko
Acquisitions.
- Average realized price, excluding net cash settlements from
commodity derivatives, decreased 57% to $26.20 per Boe in 2015 from
$60.46 per Boe in 2014 driven by the significant decline in
commodity prices as well as the increase in NGL and natural gas
production as a percentage of total production. Average realized
oil price decreased 50% to $45.22 in 2015 from $89.59 in 2014
driven by a decrease in the average WTI crude oil price of $48.62
per Bbl partially offset by a decrease in realized regional
differentials. Average realized natural gas price decreased 43% to
$2.58 per Mcf in 2015 from $4.52 per Mcf in 2014. This decrease is
a result of the decrease in the average Henry Hub natural gas index
price of approximately $1.65 per Mcf as well as the inclusion of
lower priced natural gas production from the WPX Acquisition.
Finally, our average realized NGL price decreased 59% to $0.41 per
gallon in 2015 from $1.00 per gallon in 2014. This decrease is due
to the combination of lower commodity prices and the full-period
inclusion of lower priced NGL production from the WPX
Acquisition.
- Despite additional expenses from our WPX Acquisition, Anadarko
Acquisitions and other recent acquisitions of approximately $24.0
million, our production expenses, excluding ad valorem taxes,
increased only 1% to $134.7 million in 2015 from $133.5 million in
2014. On an average cost per Boe basis, production expenses
decreased 30% to $13.63 per Boe in 2015 from $19.56 per Boe in
2014. These significant savings were driven primarily by expense
reduction efforts across our historical property set ($22.8
million) as well as the inclusion of lower cost natural gas
properties acquired in the WPX Acquisition and the Anadarko
Acquisitions.
- Non-cash impairment expense totaled $307.5 million driven by
the significant decline in natural gas futures prices during the
first and third quarters of 2015.
- General and administrative expenses, excluding unit-based LTIP
compensation expense totaled $30.5 million in 2015 compared to
$26.9 million in 2014. This increase was primarily due to a $2.9
million increase in acquisition costs between the periods as we
incurred approximately $8.2 million of one-time acquisition-related
expenses during 2015 associated with the Anadarko Acquisitions and
the establishment of the Development Agreement.
- Cash settlements received on our commodity derivatives during
2015 were $104.3 million compared to cash settlements paid of
approximately $12.0 million in 2014.
- Total development capital expenditures decreased to $29.7
million in 2015 from $91.4 million in 2014. The 2015 activity was
comprised mainly of the drilling and completion of two horizontal
Wolfcamp wells, completion costs on an operated horizontal Bone
Springs well, drilling and completion costs on two non-operated
horizontal wells and capital costs related to CO2 properties.
Commodity Derivative Contracts
We enter into oil and natural gas derivative contracts to help
mitigate the risk of changing commodity prices. As of
November 4, 2015, we had entered into derivative agreements to
receive average NYMEX WTI crude oil prices and NYMEX Henry Hub,
Waha, NWPL, NGPA, SoCal, San Juan and CIG-Rockies natural gas
prices as summarized below. Additionally, we have sold two call
options related to an existing WTI oil swap. These swap related
options ("swaptions") allow the counterparty on December 31, 2015
the option to increase the volumes under contract covering calendar
year 2016 to either double or triple the volumes of the current
swap, which has nominal volumes of 366,000 Bbls.
WTI Crude Oil Swaps:
Time Period |
Volumes
(Bbls) |
Average Price per
Bbl |
Price
Range per Bbl |
October-December 2015 |
100,961 |
$90.49 |
$88.50 |
- |
$99.85 |
2016 |
594,600 |
$68.37 |
$56.15 |
- |
$99.85 |
2017 |
182,500 |
$84.75 |
$84.75 |
WTI Crude Oil 3-Way Collars:
|
|
Average Short Put |
Average Long Put |
Average Short Call |
Time Period |
Volumes
(Bbls) |
Price per
Bbl |
Price per
Bbl |
Price per
Bbl |
October-December 2015 |
336,720 |
$64.78 |
$89.78 |
$110.57 |
2016 |
621,300 |
$63.37 |
$88.37 |
$106.40 |
2017 |
72,400 |
$60.00 |
$85.00 |
$104.20 |
WTI Crude Oil Enhanced Swaps:
|
|
|
Average Short Put |
Average Swap |
Time
Period |
Volumes
(Bbls) |
Price per
Bbl |
Price per
Bbl |
October-December 2015 |
253,000 |
$77.73 |
$93.98 |
|
|
|
|
|
|
|
Average Long Put |
Average Short Put |
Average Swap |
Time Period |
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 |
October-December 2015 |
828,000 |
$ (1.78) |
$ (1.75) |
- |
$ (1.90) |
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 and Waha):
|
|
Average |
|
|
|
Time Period |
Volumes
(MMBtu) |
Price per
MMBtu |
Price
Range per MMBtu |
October-December 2015 |
7,348,600 |
$3.96 |
$3.11 |
- |
$5.82 |
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):
|
Volumes |
Average Short Put |
Average Long Put |
Average Short Call |
Time Period |
(MMBtu) |
Price per
MMBtu |
Price per
MMBtu |
Price per
MMBtu |
October-December 2015 |
2,010,000 |
$3.66 |
$4.21 |
$5.01 |
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, NGPA, SoCal, San Juan and
Waha)
|
October-December 2015 |
2016 |
|
|
Average |
|
Average |
|
Volumes
(MMBtu) |
Price per
MMBtu |
Volumes
(MMBtu) |
Price per
MMBtu |
NWPL |
3,000,000 |
$ (0.13) |
14,977,818 |
$ (0.19) |
NGPL |
120,000 |
$ (0.15) |
— |
$— |
SoCal |
60,000 |
$0.19 |
— |
$— |
San Juan |
120,000 |
$ (0.12) |
2,499,780 |
$ (0.16) |
WAHA |
1,500,000 |
$ (0.10) |
— |
$— |
Location and quality differentials attributable to our
properties are not reflected in the above prices. The agreements
provide for monthly settlement based on the difference between the
agreement fixed price and the actual reference oil and natural gas
index prices.
Quarterly Report on Form 10-Q
Financial results contained herein are preliminary and subject
to the final, unaudited financial statements and related footnotes
included in Legacy's Form 10-Q which will be filed on or about
November 6, 2015.
Conference Call
As announced on October 26, 2015, Legacy will host an investor
conference call to discuss Legacy's results on Thursday, November
5, 2015 at 9:00 a.m. (Central Time). Those wishing to participate
in the conference call should dial 877-266-0479. A replay of the
call will be available through Thursday, November 12, 2015, by
dialing 855-859-2056 or 404-537-3406 and entering replay code
62019645. 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.
Cautionary Statement Relevant to Forward-Looking
Information
This press release contains forward-looking statements relating
to our operations that are based on management's current
expectations, estimates and projections about its operations. Words
such as "anticipates," "expects," "intends," "plans," "targets,"
"projects," "believes," "seeks," "schedules," "estimated," and
similar expressions are intended to identify such forward-looking
statements. These statements are not guarantees of future
performance and are subject to certain risks, uncertainties and
other factors, some of which are beyond our control and are
difficult to predict. Among the important factors that could cause
actual results to differ materially from those in the
forward-looking statements are: realized oil and natural gas
prices; production volumes, lease operating expenses, general and
administrative costs and finding and development costs; future
operating results and the factors set forth under the heading "Risk
Factors" in our annual and quarterly reports filed with the SEC.
Therefore, actual outcomes and results may differ materially from
what is expressed or forecasted in such forward-looking statements.
The reader should not place undue reliance on these forward-looking
statements, which speak only as of the date of this press release.
Unless legally required, Legacy undertakes no obligation to update
publicly any forward-looking statements, whether as a result of new
information, future events or otherwise.
LEGACY RESERVES
LP |
CONDENSED CONSOLIDATED
STATEMENTS OF OPERATIONS |
(UNAUDITED) |
|
|
|
|
|
|
Three Months
Ended |
Nine Months
Ended |
|
September 30, |
September 30, |
|
2015 |
2014 |
2015 |
2014 |
|
(In thousands, except
per unit data) |
Revenues: |
|
|
|
|
Oil sales |
$ 49,779 |
$ 105,640 |
$ 159,188 |
$ 316,426 |
Natural gas liquids (NGL)
sales |
2,946 |
10,413 |
12,867 |
19,482 |
Natural gas sales |
36,773 |
33,623 |
86,783 |
76,786 |
Total
revenues |
89,498 |
149,676 |
258,838 |
412,694 |
|
|
|
|
|
Expenses: |
|
|
|
|
Oil and natural gas
production |
48,446 |
55,491 |
142,886 |
143,834 |
Production and other taxes |
4,834 |
7,742 |
13,038 |
24,292 |
General and administrative |
16,246 |
8,325 |
35,506 |
30,781 |
Depletion, depreciation,
amortization and accretion |
45,041 |
48,016 |
122,306 |
120,250 |
Impairment of long-lived
assets |
98,054 |
4,785 |
307,455 |
8,583 |
(Gain) loss on disposal of
assets |
560 |
(1,683) |
1,567 |
(3,235) |
Total
expenses |
213,181 |
122,676 |
622,758 |
324,505 |
|
|
|
|
|
Operating income
(loss) |
(123,683) |
27,000 |
(363,920) |
88,189 |
|
|
|
|
|
Other income (expense): |
|
|
|
|
Interest income (expense) |
(55) |
223 |
326 |
662 |
Interest expense |
(23,351) |
(19,083) |
(58,903) |
(49,247) |
Equity in income (loss) of
equity method investees |
(6) |
126 |
97 |
309 |
Net gains on commodity
derivatives |
57,000 |
55,994 |
63,982 |
8,675 |
Other |
19 |
(166) |
723 |
137 |
Incomes (loss)
before income taxes |
(90,076) |
64,094 |
(357,695) |
48,725 |
Income tax (expense) benefit |
(1) |
(278) |
290 |
(870) |
Net income
(loss) |
$ (90,077) |
$ 63,816 |
$ (357,405) |
$ 47,855 |
Distributions to
Preferred unitholders |
(4,750) |
(4,750) |
(14,250) |
(6,944) |
Net income (loss)
attributable to unitholders |
$ (94,827) |
$ 59,066 |
$ (371,655) |
$ 40,911 |
|
|
|
|
|
Income (loss) per
unit - basic |
$ (1.38) |
$ 1.03 |
$ (5.39) |
$ 0.71 |
Income (loss) per
unit - diluted |
$ (1.38) |
$ 1.02 |
$ (5.39) |
$ 0.71 |
Weighted average
number of units used in computing net loss per unit -- |
|
|
|
|
Basic |
68,945 |
57,406 |
68,921 |
57,363 |
Diluted |
68,945 |
57,643 |
68,921 |
57,523 |
|
|
|
|
|
|
|
|
|
|
LEGACY RESERVES
LP |
CONDENSED CONSOLIDATED
BALANCE SHEETS |
(UNAUDITED) |
ASSETS |
|
September 30, |
December 31, |
|
2015 |
2014 |
|
(In
thousands) |
Current assets: |
|
|
Cash |
$ 1,627 |
$ 725 |
Accounts receivable, net: |
|
|
Oil and natural
gas |
48,381 |
49,390 |
Joint interest
owners |
27,795 |
16,235 |
Other |
130 |
237 |
Fair value of derivatives |
64,500 |
120,305 |
Prepaid expenses and other
current assets |
5,487 |
5,362 |
Total current
assets |
147,920 |
192,254 |
Oil and natural gas properties using the
successful efforts method, at cost: |
|
|
Proved properties |
3,502,151 |
2,946,820 |
Unproved properties |
48,773 |
47,613 |
Accumulated depletion,
depreciation, amortization and impairment |
(1,766,523) |
(1,354,459) |
|
1,784,401 |
1,639,974 |
Other property and equipment, net of
accumulated depreciation and amortization of $8,489 and $7,446,
respectively |
4,300 |
3,767 |
Operating rights, net of amortization of
$4,842 and $4,509, respectively |
2,175 |
2,508 |
Fair value of derivatives |
48,269 |
32,794 |
Other assets, net of amortization of $14,774
and $12,551, respectively |
23,623 |
24,255 |
Investments in equity method investees |
617 |
3,054 |
Total assets |
$ 2,011,305 |
$ 1,898,606 |
LIABILITIES AND
PARTNERS' EQUITY |
Current liabilities: |
|
|
Accounts payable |
$ 3,317 |
$ 2,787 |
Accrued oil and natural gas
liabilities |
59,244 |
78,615 |
Fair value of derivatives |
3,266 |
2,080 |
Asset retirement
obligation |
3,028 |
3,028 |
Other |
25,442 |
11,066 |
Total current
liabilities |
94,297 |
97,576 |
Long-term debt |
1,451,700 |
938,876 |
Asset retirement obligation |
285,306 |
223,497 |
Fair value of derivatives |
807 |
— |
Other long-term liabilities |
1,229 |
1,452 |
Total liabilities |
1,833,339 |
1,261,401 |
Commitments and contingencies |
|
|
Partners' equity |
|
|
Series A Preferred equity -
2,300,000 units issued and outstanding at September 30, 2015 and
December 31, 2014 |
55,192 |
55,192 |
Series B Preferred equity -
7,200,000 units issued and outstanding at September 30, 2015 and
December 31, 2014 |
174,261 |
174,261 |
Incentive distribution equity -
100,000 units issued and outstanding at September 30, 2015 and
December 31, 2014 |
30,814 |
30,814 |
Limited partners' equity
(deficit) - 68,949,561 and 68,910,784 units issued and outstanding
at September 30, 2015 and December 31, 2014, respectively |
(82,259) |
376,885 |
General partner's equity
(deficit) (approximately 0.03%) |
(42) |
53 |
Total partners' equity |
177,966 |
637,205 |
Total liabilities and partners' equity |
$ 2,011,305 |
$ 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.
The following table presents a reconciliation of our
consolidated net income (loss) to Adjusted EBITDA and Distributable
Cash Flow:
|
Three Months
Ended |
Nine Months
Ended |
|
September 30, |
September 30, |
|
2015 |
2014 |
2015 |
2014 |
|
(In
thousands) |
Net income (loss) |
$ (90,077) |
$ 63,816 |
$ (357,405) |
$ 47,855 |
Plus: |
|
|
|
|
Interest expense |
23,351 |
19,083 |
58,903 |
49,247 |
Income tax expense
(benefit) |
1 |
278 |
(290) |
870 |
Depletion, depreciation,
amortization and accretion |
45,041 |
48,016 |
122,306 |
120,250 |
Impairment of long-lived
assets |
98,054 |
4,785 |
307,455 |
8,583 |
(Gain) loss on disposal of
assets |
560 |
(1,683) |
1,567 |
(3,235) |
Equity in income (loss) of
equity method investees |
6 |
(126) |
(97) |
(309) |
Unit-based compensation
expense |
1,704 |
1,025 |
4,985 |
3,855 |
Minimum payments received in
excess of overriding royalty interest earned(1) |
386 |
349 |
1,130 |
1,023 |
Equity in EBITDA of equity
method investee(2) |
— |
150 |
169 |
649 |
Net gains on commodity
derivatives |
(57,000) |
(55,994) |
(63,983) |
(8,675) |
Net cash settlements received
(paid) on commodity derivatives |
26,788 |
(2,354) |
104,314 |
(11,974) |
Transaction expenses related to
acquisitions |
6,502 |
364 |
8,175 |
5,330 |
Adjusted EBITDA |
$ 55,316 |
$ 77,709 |
$ 187,229 |
$ 213,469 |
|
|
|
|
|
Less: |
|
|
|
|
Cash interest expense |
18,632 |
18,456 |
52,624 |
47,639 |
Cash settlements of LTIP unit
awards |
— |
86 |
— |
771 |
Estimated maintenance capital
expenditures(3) |
NM* |
18,200 |
NM* |
54,200 |
Development capital
expenditures(4) |
7,881 |
NM* |
29,663 |
NM* |
Distributions on Series A and
Series B preferred units |
4,750 |
4,750 |
14,250 |
6,944 |
Distributable Cash
Flow(3) |
$ 24,053 |
$ 36,217 |
$ 90,692 |
$ 103,915 |
|
|
|
|
|
Distributions Attributable to Each
Period(5) |
$ 10,425 |
$ 42,191 |
$ 58,957 |
$ 111,621 |
|
|
|
|
|
Distribution Coverage
Ratio(3)(6) |
2.31x |
0.86x |
1.54x |
0.93x |
* Not meaningful due to the 2015 change in presentation
(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.
(2) Equity in EBITDA of 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.
(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 2015, 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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