Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced first
quarter results for 2015. Financial results contained herein are
preliminary and subject to the final, unaudited financial
statements included in Legacy's Form 10-Q to be filed on or about
May 8, 2015.
Q1 highlights include:
- Record production of 33,778 Boe/d, up 3% from Q4 2014 and 73%
from Q1 2014
- Adjusted EBITDA of $62.0 million
- Distributable Cash Flow of $26.8 million, covering our
quarterly distribution by 1.11 times
Paul T. Horne, President and Chief Executive Officer of Legacy
commented, "The highlight of this quarter was our rapid response to
the current commodity price environment by aggressively driving
down our costs. We realized a production expense reduction of
approximately 14% from Q4 2014 to Q1 2015. This is the response we
needed to see in this challenging commodity price environment and I
applaud the team for their excellent work. These efforts
contributed to our first quarter distribution coverage of 1.11x and
our continued efforts will help us realize coverage in excess of
1.3x on our revised quarterly distribution for the remainder of
2015.
We spent approximately $13 million in Q1 on oil and natural gas
development, nearly 45% of our 2015 capital budget, including our
first two horizontal Wolfcamp wells. We are encouraged by
those initial results and expect continued operational and cost
improvement should we resume this program later in the year. On the
business development front, we have continued to evaluate our
options to monetize portions of our undeveloped Permian acreage and
have seen significant private investor interest in a DrillCo
structure. As mentioned in our prior release, we are continuing our
business development efforts and we remain optimistic in our
ability to put our balance sheet to work in making accretive
acquisitions that fit our MLP profile."
Dan Westcott, Executive Vice President and Chief Financial
Officer of Legacy commented, "On March 27, 2015, we closed our
Spring borrowing base redetermination resulting in a reaffirmed
$700 million borrowing base. Today we have nearly $588 million of
availability under our revolver. We have refined our 2015 financial
guidance and, based on those projections, we expect to cover our
recently-reduced annualized cash distribution of $1.40 by 1.3x. We
also expect to be free cash flow positive in 2015 which should
translate into modest debt reduction over the course of the
year.
We remain optimistic that continued operational improvements,
cost reductions and successful business development opportunities
will enable Legacy to deliver significant unitholder value in the
current commodity price environment. We remain focused on
maximizing unitholder value by protecting our cash flow and yet
continue to position ourselves for recovery in commodity
prices."
LEGACY RESERVES
LP |
SELECTED FINANCIAL AND
OPERATING DATA |
|
|
Three Months
Ended |
|
March
31, |
|
2015 |
2014 |
|
(In thousands, except
per unit data) |
Revenues: |
|
|
Oil sales |
$ 50,296 |
$ 102,055 |
Natural gas liquids sales |
4,192 |
3,965 |
Natural gas sales |
27,051 |
19,883 |
Total revenue |
$ 81,539 |
$ 125,903 |
Expenses: |
|
|
Oil and natural gas production, excluding
ad valorem taxes |
$ 45,944 |
$ 39,638 |
Ad valorem taxes |
$ 3,276 |
$ 2,896 |
Total oil and natural gas production |
$ 49,220 |
$ 42,534 |
Production and other taxes |
$ 4,218 |
$ 7,955 |
General and administrative, excluding
LTIP |
$ 7,781 |
$ 6,957 |
LTIP expense |
$ 1,088 |
$ 690 |
Total general and administrative |
$ 8,869 |
$ 7,647 |
Depletion, depreciation,
amortization and accretion |
$ 41,068 |
$ 33,697 |
Commodity derivative cash settlements: |
|
|
Oil derivative cash settlements received
(paid) |
$ 32,200 |
$ (2,556) |
Natural gas derivative cash settlements
received (paid) |
$ 8,137 |
$ (1,054) |
Production: |
|
|
Oil (MBbls) |
1,200 |
1,135 |
Natural gas liquids (MGal) |
9,686 |
3,362 |
Natural gas (MMcf) |
9,658 |
3,226 |
Total (MBoe) |
3,040 |
1,753 |
Average daily production (Boe/d) |
33,778 |
19,478 |
Average sales price per unit (excluding
derivative cash settlements): |
|
|
Oil price (per Bbl) |
$ 41.91 |
$ 89.92 |
Natural gas liquids price (per Gal) |
$ 0.43 |
$ 1.18 |
Natural gas price (per Mcf) |
$ 2.80 |
$ 6.16 |
Combined (per Boe) |
$ 26.82 |
$ 71.82 |
Average sales price per unit (including
derivative cash settlements): |
|
|
Oil price (per Bbl) |
$ 68.75 |
$ 87.66 |
Natural gas liquids price (per Gal) |
$ 0.43 |
$ 1.18 |
Natural gas price (per Mcf) |
$ 3.64 |
$ 5.84 |
Combined (per Boe) |
$ 40.09 |
$ 69.76 |
Average WTI oil spot price (per Bbl) |
$ 48.57 |
$ 98.68 |
Average Henry Hub natural gas index price
(per Mcf) |
$ 2.81 |
$ 4.93 |
Average unit costs per Boe: |
|
|
Oil and natural gas production |
$ 15.11 |
$ 22.61 |
Ad valorem taxes |
$ 1.08 |
$ 1.65 |
Production and other taxes |
$ 1.39 |
$ 4.54 |
General and administrative excluding
LTIP |
$ 2.56 |
$ 3.97 |
Total general and administrative |
$ 2.92 |
$ 4.36 |
Depletion, depreciation, amortization and
accretion |
$ 13.51 |
$ 19.22 |
|
|
|
Financial and Operating Results - First
Quarter 2015 Compared to First Quarter 2014
- Production increased 73% to a record of 33,778 Boe/d from
19,478 Boe/d primarily due to acquisitions in 2014 including our
acquisition of non-operated interest in oil and natural gas
properties located in the Piceance Basin in Garfield County,
Colorado from WPX Energy, Inc ("WPX Acquisition").
- Average realized price, excluding net cash settlements from
commodity derivatives, decreased 63% to $26.82 per Boe in 2015 from
$71.82 per Boe in 2014. This decrease in realized prices was
primarily 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 53% to $41.91 in 2015 from $89.92 in 2014 driven by a
decrease in the average West Texas Intermediate ("WTI") crude oil
price of $50.11 per Bbl partially offset by a decrease in realized
regional differentials. Average realized natural gas price
decreased 55% to $2.80 per Mcf in 2015 from $6.16 per Mcf in 2014.
This decrease was a result of the decrease in the average
Henry Hub natural gas index price of approximately $2.12 per Mcf as
well as the inclusion of lower priced natural gas production from
the WPX Acquisition. Finally, our average realized NGL price
decreased 64% to $0.43 per gallon in 2015 from $1.18 per gallon in
2014. This decrease is due to the combination of lower commodity
prices and the inclusion of lower priced NGL production from the
WPX Acquisition.
- Production expenses, excluding ad valorem taxes, increased 16%
to $45.9 million in 2015 from $39.6 million in 2014. On an average
cost per Boe basis, production expenses decreased 33% to $15.11 per
Boe in 2015 from $22.61 per Boe in 2014, driven primarily by the
inclusion of lower cost natural gas properties acquired in the WPX
Acquisition as well as reduced expenses across properties that we
have owned prior to the WPX Acquisition.
- Non-cash impairment expense totaled $209.4 million driven by
the significant decline in natural gas futures prices during the
first quarter of 2015.
- General and administrative expenses, excluding unit-based
Long-Term Incentive Plan ("LTIP") compensation expense totaled $7.8
million in 2015 compared to $7.0 million in 2014. This increase was
primarily due to an increase in personnel costs to support recent
acquisitions.
- Cash settlements received on our commodity derivatives during
2015 were $40.3 million compared to cash settlements paid of
approximately $3.6 million in 2014.
- Total development capital expenditures decreased to $13.4
million in 2015 from $21.8 million in 2014. The 2015 activity was
comprised mainly of the drilling and completion of two horizontal
Wolfcamp wells, completion costs on a horizontal Bone Springs well
and capital costs related to CO2 injection properties. Our
non-operated capital expenditures were less than 1% of total
capital for the quarter compared to 32% in 2014.
Updated Financial Guidance
The following table sets forth certain assumptions used by
Legacy to estimate its anticipated results of operations for 2015.
These estimates do not include any acquisitions of additional oil
or natural gas properties. In addition, these estimates are based
on, among other things, assumptions of capital expenditure levels,
current indications of supply and demand for oil and natural gas
and current operating and labor costs. The guidance set forth below
does not constitute any form of guarantee, assurance or promise
that the matters indicated will actually be achieved. The
guidance below sets forth management's best estimate based on
current and anticipated market conditions and other factors. While
we believe that these estimates and assumptions are reasonable,
they are inherently uncertain and are subject to, among other
things, significant business, economic, regulatory, environmental
and competitive risks and uncertainties that could cause actual
results to differ materially from those we anticipate, as set forth
under "Cautionary Statement Relevant to Forward-Looking
Information."
|
Implied 2015
Range |
|
($ in thousands unless
otherwise noted) |
Production: |
|
|
|
Oil (MBbls) |
4,570 |
-- |
4,690 |
Natural gas liquids (MGal) |
38,400 |
-- |
39,400 |
Natural gas (MMcf) |
37,500 |
-- |
38,450 |
Total (MBoe) |
11,734 |
-- |
12,036 |
Average daily production (Boe/d) |
32,148 |
-- |
32,975 |
|
|
|
|
Weighted Average NYMEX
Differentials: |
|
|
|
Oil (per Bbl) |
$ (7.25) |
-- |
$ (6.25) |
NGL realization (1) |
0.93% |
-- |
0.98% |
Natural gas (per Mcf) |
$0.00 |
-- |
$0.05 |
|
|
|
|
Expenses: |
|
|
|
Oil and natural gas production expenses
($/Boe) |
$15.00 |
-- |
$16.00 |
Ad valorem and production taxes (% of
revenue) |
8.25% |
-- |
8.65% |
Cash G&A expenses (2) |
$30,000 |
-- |
$32,000 |
|
|
|
|
Capital expenditures: |
|
|
|
Total development capital expenditures |
$29,500 |
-- |
$30,500 |
|
|
|
|
Note: Figures above do not include any
assumed acquisitions. |
|
|
|
|
|
|
|
(1) Represents the
projected percentage of WTI crude oil prices divided by 42, as we
report NGLs in gallons. |
(2) Consistent with our
definition of Adjusted EBITDA, these figures exclude LTIP expenses.
Cash settlements of LTIP (not included herein) impact Distributable
Cash Flow. |
|
Commodity Derivative Contracts
We enter into oil and natural gas derivative contracts to help
mitigate the risk of changing commodity prices. As of May 6,
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:
WTI Crude Oil Swaps:
Time Period |
Volumes (Bbls) |
Average Price per
Bbl |
Price Range per
Bbl |
April-December 2015 |
914,735 |
$79.14 |
$52.00 |
-- |
$100.20 |
2016 |
228,600 |
$87.94 |
$86.30 |
-- |
$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 |
April-December 2015 |
997,400 |
$64.87 |
$89.60 |
$111.39 |
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 |
April-December 2015 |
688,000 |
$77.01 |
$93.79 |
|
|
|
|
|
|
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 |
April-December 2015 |
2,475,000 |
$ (1.77) |
$ (1.65) |
-- |
$ (1.90) |
2016 |
1,464,000 |
$ (1.70) |
$ (1.65) |
-- |
$ (1.75) |
Natural Gas Swaps (Henry Hub, Waha and CIG-Rockies):
|
|
Average |
|
|
|
Time Period |
Volumes (MMBtu) |
Price per MMBtu |
Price Range per
MMBtu |
April-December 2015 |
13,963,300 |
$4.39 |
$3.98 |
-- |
$5.82 |
2016 |
1,419,200 |
$4.30 |
$4.12 |
-- |
$5.30 |
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 |
April-December 2015 |
6,030,000 |
$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):
|
April-December
2015 |
|
|
Average |
|
Volumes (MMBtu) |
Price per MMBtu |
NWPL |
9,000,000 |
$ (0.13) |
NGPL |
360,000 |
$ (0.15) |
SoCal |
180,000 |
$0.19 |
San Juan |
360,000 |
$ (0.12) |
WAHA |
4,500,000 |
$ (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
Our consolidated financial statements and related footnotes will
be available in our Form 10-Q which will be filed on or about
May 8, 2015.
Ongoing Proxy Process
We are currently seeking the vote of all unitholders through our
2015 proxy process. Our proxy can be found at:
http://ir.legacylp.com/proxy.cfm. If you have lost your voting
instructions, please contact your bank or broker with whom you hold
your units. If you have questions about the voting process, please
do not hesitate to contact us at 432-689-5200. We appreciate your
support.
Conference Call
As announced on April 20, 2015, Legacy will host an investor
conference call to discuss Legacy's results on Thursday, May 7,
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, May 14, 2015, by dialing
855-859-2056 or 404-537-3406 and entering replay code 24970195.
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, 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 |
|
March
31, |
|
2015 |
2014 |
|
(In thousands, except
per unit data) |
Revenues: |
|
|
Oil sales |
$ 50,296 |
$ 102,055 |
Natural gas liquids (NGL) sales |
4,192 |
3,965 |
Natural gas sales |
27,051 |
19,883 |
Total revenues |
81,539 |
125,903 |
|
|
|
Expenses: |
|
|
Oil and natural gas production |
49,220 |
42,534 |
Production and other taxes |
4,218 |
7,955 |
General and administrative |
8,869 |
7,647 |
Depletion, depreciation, amortization and
accretion |
41,068 |
33,697 |
Impairment of long-lived assets |
209,402 |
1,412 |
Loss on disposal of assets |
1,941 |
2,301 |
Total expenses |
314,718 |
95,546 |
|
|
|
Operating income (loss) |
$ (233,179) |
30,357 |
|
|
|
Other income (expense): |
|
|
Interest income |
206 |
223 |
Interest expense |
$ (17,792) |
$ (13,939) |
Equity in income of equity method
investees |
79 |
(8) |
Net gains (losses) on commodity
derivatives |
20,480 |
(15,886) |
Other |
605 |
93 |
Income (loss) before income taxes |
$ (229,601) |
840 |
Income tax (expense) benefit |
747 |
(314) |
Net income (loss) |
$ (228,854) |
$ 526 |
Distributions to Preferred
unitholders |
$ (4,750) |
— |
Net income (loss) attributable to
unitholders |
$ (233,604) |
$ 526 |
|
|
|
Income (loss) per unit - basic and
diluted |
$ (3.39) |
$ 0.01 |
Weighted average number of units used in
computing net income (loss) per unit -- |
|
|
Basic |
68,921 |
57,309 |
Diluted |
68,921 |
57,367 |
|
|
|
LEGACY RESERVES
LP |
CONDENSED
CONSOLIDATED BALANCE SHEETS |
(UNAUDITED) |
|
ASSETS |
|
March
31, |
December
31, |
|
2015 |
2014 |
|
(In
thousands) |
Current assets: |
|
|
Cash |
$ 3,451 |
$ 725 |
Accounts receivable, net: |
|
|
Oil and natural gas |
38,658 |
49,390 |
Joint interest owners |
22,108 |
16,235 |
Other |
259 |
237 |
Fair value of derivatives |
104,541 |
120,305 |
Prepaid expenses and other current
assets |
4,403 |
5,362 |
Total current assets |
173,420 |
192,254 |
Oil and natural gas properties using the
successful efforts method, at cost: |
|
|
Proved properties |
2,972,336 |
2,946,820 |
Unproved properties |
48,159 |
47,613 |
Accumulated depletion, depreciation,
amortization and impairment |
(1,601,883) |
(1,354,459) |
|
1,418,612 |
1,639,974 |
Other property and equipment, net of
accumulated depreciation and amortization of $7,791 and $7,446,
respectively |
3,560 |
3,767 |
Operating rights, net of amortization of
$4,620 and $4,509, respectively |
2,397 |
2,508 |
Fair value of derivatives |
28,701 |
32,794 |
Other assets, net of amortization of $13,243
and $12,551, respectively |
25,647 |
24,255 |
Investments in equity method investees |
3,053 |
3,054 |
Total assets |
$ 1,655,390 |
$ 1,898,606 |
LIABILITIES AND
PARTNERS' EQUITY |
Current liabilities: |
|
|
Accounts payable |
$ 3,069 |
$ 2,787 |
Accrued oil and natural gas
liabilities |
55,352 |
78,615 |
Fair value of derivatives |
1,540 |
2,080 |
Asset retirement obligation |
3,028 |
3,028 |
Other |
24,204 |
11,066 |
Total current liabilities |
87,193 |
97,576 |
Long-term debt |
967,440 |
938,876 |
Asset retirement obligation |
237,218 |
223,497 |
Other long-term liabilities |
1,328 |
1,452 |
Total liabilities |
1,293,179 |
1,261,401 |
Commitments and contingencies |
|
|
Partners' equity |
|
|
Series A Preferred equity - 2,300,000
units issued and outstanding at March 31, 2015 and December 31,
2014 |
55,192 |
55,192 |
Series B Preferred equity - 7,200,000
units issued and outstanding at March 31, 2015 and December 31,
2014 |
174,261 |
174,261 |
Incentive distribution equity - 100,000
units issued and outstanding at March 31, 2015 and December 31,
2014 |
30,814 |
30,814 |
Limited partners' equity - 68,930,150 and
68,910,784 units issued and outstanding at March 31, 2015 and
December 31, 2014, respectively |
101,952 |
376,885 |
General partner's equity (approximately
0.03%) |
(8) |
53 |
Total partners' equity |
362,211 |
637,205 |
Total liabilities and partners' equity |
$ 1,655,390 |
$ 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 |
|
March
31, |
|
2015 |
2014 |
|
(In
thousands) |
Net income (loss) |
$ (228,854) |
$ 526 |
Plus: |
|
|
Interest expense |
17,792 |
13,939 |
Income tax expense (benefit) |
(747) |
314 |
Depletion, depreciation, amortization and
accretion |
41,068 |
33,697 |
Impairment of long-lived assets |
209,402 |
1,412 |
(Gain) loss on disposal of assets |
1,941 |
2,301 |
Equity in income of equity method
investees |
(79) |
8 |
Unit-based compensation expense |
1,088 |
690 |
Minimum payments received in excess of
overriding royalty interest earned(1) |
367 |
333 |
Equity in EBITDA of equity method
investee(2) |
119 |
258 |
Net (gains) losses on commodity
derivatives |
(20,480) |
15,886 |
Net cash settlements received (paid) on
commodity derivatives |
40,337 |
(3,610) |
Transaction expenses related to
acquisitions |
25 |
55 |
Adjusted EBITDA |
$ 61,979 |
$ 65,809 |
|
|
|
Less: |
|
|
Cash interest expense |
17,042 |
13,594 |
Cash settlements of LTIP unit awards |
— |
125 |
Estimated maintenance capital
expenditures(3) |
NM* |
17,800 |
Development capital expenditures(4) |
13,366 |
NM* |
Distributions on Series A and Series B
preferred units |
4,750 |
— |
Distributable Cash
Flow(3) |
$ 26,821 |
$ 34,290 |
|
|
|
Distributions Attributable to Each
Period(5) |
$ 24,223 |
$ 34,251 |
|
|
|
Distribution Coverage
Ratio(3)(6) |
1.11x |
1.00x |
|
|
|
* 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. |
(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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