Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced second
quarter results for 2014. Financial results contained herein are
preliminary and subject to the final, unaudited financial
statements included in Legacy's 10-Q to be filed on or about August
1, 2014.
Q2 and YTD 2014 highlights include:
- Successful closing of our Strategic Alliance with WPX Energy
along with closings of our two previously announced acquisitions in
Chaves County, NM and Sheridan County, MT.
- Record production of 23,286 and 21,392 Boe/d for the three and
six month periods, respectively.
- Record revenue of $137.1 million and $263.0 million for the
three and six month periods, respectively.
- Adjusted EBITDA of $70.0 million and $135.8 million for the
three and six month periods, respectively.
- Distributable Cash Flow of $33.4 million and $67.7 million for
the three and six month periods, respectively.
- A $57.5 million Series A Preferred Unit issuance at 8.0%
(Nasdaq:LGCYP).
- A $180 million Series B Preferred Unit issuance at 8.0%
(Nasdaq:LGCYO).
- A $300 million tack-on offering to our 6.625% Senior Notes due
2021.
- A $0.015 per unit increase in our distribution to $0.61 per
quarter, reflecting only a partial quarter contribution from our
initial transaction with WPX Energy and representing a 10.5%
annualized growth rate.
Cary D. Brown, Chairman, President and Chief Executive Officer
of Legacy Reserves GP, LLC, the general partner of Legacy,
commented: "The second quarter is arguably our best quarter
since going public. We closed $475.5 million of long-lived,
accretive acquisitions while increasing distributions, balance
sheet strength and liquidity under our revolver. We added a
strategic partner and increased production to our highest levels to
date. These developments allowed us to increase our quarterly
distribution by $0.015, our largest quarterly increase since
2008. I am excited about the direction we are headed and the
opportunities we are seeing. We continue to see value and
great promise in our historical Permian footprint as new horizontal
wells are being added daily around our acreage. I want to
personally thank all our employees who have worked diligently to
make this possible."
Dan Westcott, Executive Vice President and Chief Financial
Officer, commented, "Q2 was indeed a great quarter. Our WPX
Acquisition is a big step and one that we will be more excited to
see fully flow through our financials next quarter. As we
mentioned in May, we are hopeful that our newly-created IDR
structure allows us to lengthen and broaden our prospects for
future growth opportunities. We have recently raised over $530
million of long-term capital including over $230 million in 8.0%
preferred equity and $300 million of additional senior
notes. These instruments further strengthen our balance sheet
with a conservative leverage profile allowing us to exit the
quarter with $625 million of availability under our $950 million
borrowing base. Our recent acquisitions are projected to
provide significant asset-level growth and, when combined with our
strong balance sheet, we look forward to seeing that increased
value flow directly to our unitholders."
Financial and Operating Results – Second Quarter 2014
Compared to Second Quarter 2013
- Production increased 19% to 23,286 Boe/d from 19,516 Boe/d
primarily due to the WPX and other recent acquisitions, which
closed during the quarter and thus contributed production for only
a portion of the quarter.
- Average realized price, excluding net cash settlements from
commodity derivatives, decreased 3% to $64.71 per Boe in 2014 from
$66.66 per Boe in 2013 due to the significant increase in natural
gas and NGL production as such products are generally less valuable
per Boe than oil. Average realized oil price increased 3% to
$92.54 per Bbl in 2014 from $89.85 per Bbl in 2013. This
increase of $2.69 per Bbl was attributable to an increase in the
average West Texas Intermediate ("WTI") crude oil price of $9.30
per Bbl partially offset by higher realized regional
differentials. Average realized natural gas price remained
relatively flat at $4.77 per Mcf in 2014 compared to $4.76 per Mcf
in 2013. While the average Henry Hub natural gas price index
increased by $1.34 per Mcf in 2014, this increase was offset by
relatively lower realized gas prices from the gas production
associated with the WPX acquisition. Finally, our average
realized NGL price decreased 3% to $0.92 per gallon in 2014 from
$0.95 per gallon in 2013. The large majority of our
separately-reported NGL production is from our Mid-Continent and
Rockies regions.
- Production expenses, excluding ad valorem taxes, increased 23%
to $42.1 million in 2014 from $34.3 million in
2013. Production expenses increased primarily due to increased
production resulting from additional properties acquired in Q2 of
2014 and the second half of 2013 as well as development activities
and industry-wide cost increases.
- Legacy's general and administrative expenses excluding
unit-based/Long-Term Incentive Plan ("LTIP") compensation expense
increased to $12.7 million in 2014 compared to $5.7 million in
2013. This increase was primarily attributable to $4.9 million
of one-time acquisition related expenses as well as an increase in
salary and benefit expenses related to the hiring of additional
personnel to manage our larger asset base.
- Cash settlements paid on our commodity derivatives were $6.0
million during 2014 compared to $1.4 million in 2013, a $4.6
million change between the periods.
- Total development capital expenditures were $36.1 million in
2014 and were heavily weighted towards our Permian Wolfberry and
Bone Spring drilling. Non-operated capital expenditures
comprised 14% of our total capital expenditures in 2014 with
activity primarily in the Permian and Mid-Continent.
Financial and Operating Results – Second Quarter Year to
Date 2014 Compared to Second Quarter Year to Date 2013
- Production increased 9% to 21,392 Boe/d from 19,613 Boe/d
primarily due to the WPX and other recent acquisitions, which
closed during the quarter and thus contributed production for only
a portion of the quarter. These increases were partially offset by
production declines in our Lower Abo assets as well as downtime
related to inclement weather in the first quarter of 2014.
- Average realized price, excluding net cash settlements from
commodity derivatives, increased 6% to $67.93 per Boe in 2014 from
$64.02 per Boe in 2013. Average realized oil price increased
7% to $91.25 per Bbl in 2014 from $85.43 per Bbl in 2013. This
increase of $5.82 per Bbl was attributable to an increase in the
average WTI crude oil price of $6.87 per Bbl partially offset by
higher realized regional differentials. Average realized
natural gas price increased 18% to $5.33 per Mcf in 2014 from $4.53
per Mcf in 2013. While the average Henry Hub natural gas price
index increased by $1.09 per Mcf in 2014, this increase was
partially offset by lower realized gas prices from the gas
production associated with the WPX acquisition as compared to the
prices realized by our Permian and Mid-Continent
assets. Finally, our average realized NGL price decreased 2%
to $1.02 per gallon in 2014 from $1.05 per gallon in 2013. The
large majority of our separately reported NGL production is from
our Mid-Continent and Rockies regions.
- Production expenses, excluding ad valorem taxes, increased 23%
to $81.7 million in 2014 from $66.7 million in
2013. Production expenses increased primarily due to increased
production resulting from additional properties added in Q2 of 2014
and the second half of 2013, remedial workovers and other one-time
well failure expenses. To a lesser extent, expenses associated
with Legacy's development activities and industry-wide cost
increases also contributed to the increase in production
expenses.
- Legacy's general and administrative expenses excluding LTIP
compensation expense increased to $19.6 million in 2014 compared to
$11.0 million in 2013. This increase was primarily
attributable to $5.0 million of one-time acquisition related
expenses as well as an increase in salary and benefit expenses
related to the hiring of additional personnel to manage our larger
asset base.
- Cash settlements paid on our commodity derivatives were $9.6
million during 2014 compared to cash receipts of $1.3 million in
2013, a $10.9 million change between the periods.
- Total development capital expenditures were $57.9 million in
2014 and were heavily weighted towards our Permian Wolfberry and
Bone Spring drilling. Non-operated capital expenditures
comprised 23% of our total capital expenditures in 2014 with
activity primarily in the Permian and Mid-Continent.
Commodity Derivatives Contracts
We enter into oil and natural gas derivatives contracts to help
mitigate the risk of changing commodity prices. As of July 30,
2014, we had entered into derivatives agreements to receive average
NYMEX WTI crude oil prices and NYMEX Henry Hub, Waha, ANR-Oklahoma,
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 |
July-December 2014 |
1,599,902 |
$93.58 |
$87.50 - $101.50 |
2015 |
1,056,301 |
$93.93 |
$88.50 - $100.20 |
2016 |
228,600 |
$87.94 |
$86.30 - $99.85 |
2017 |
182,500 |
$84.75 |
$84.75 |
WTI Crude Oil 3-Way Collars:
Time Period |
Volumes (Bbls) |
Average Short Put Price per
Bbl |
Average Long Put Price per
Bbl |
Average Short Call Price per
Bbl |
July-December 2014 |
404,800 |
$71.59 |
$96.59 |
$110.71 |
2015 |
1,362,800 |
$65.08 |
$89.69 |
$111.84 |
2016 |
621,300 |
$63.37 |
$88.37 |
$106.40 |
2017 |
72,400 |
$60.00 |
$85.00 |
$104.20 |
WTI Crude Oil Enhanced Swaps:
Time Period |
Volumes (Bbls) |
Average Long Put Price per
Bbl |
Average Short Put Price per
Bbl |
Average Swap Price per
Bbl |
2015 |
365,000 |
$60.00 |
$80.00 |
$92.35 |
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 |
|
|
|
|
|
Time Period |
Volumes (Bbls) |
Average Short Put Price per
Bbl |
Average Swap Price per
Bbl |
|
2015 |
503,000 |
$74.12 |
$93.09 |
|
Natural Gas Swaps (Henry Hub, WAHA, ANR-Oklahoma and
CIG-Rockies):
Time Period |
Volumes (MMBtu) |
Average Price per
MMBtu |
Price Range per
MMBtu |
July-December 2014 |
12,625,262 |
$4.64 |
$3.61 - $6.47 |
2015 |
16,219,300 |
$4.45 |
$4.15 - $5.82 |
2016 |
1,419,200 |
$4.30 |
$4.12 - $5.30 |
Natural Gas 3-Way Collars (Henry Hub):
Time Period |
Volumes (MMBtu) |
Average Short Put Price per
MMBtu |
Average Long Put Price per
MMBtu |
Average Short Call Price per
MMBtu |
July-December 2014 |
240,000 |
$4.00 |
$4.65 |
$5.03 |
2015 |
8,040,000 |
$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):
|
July-December
2014 |
2015 |
|
Volumes |
Average Price per
MMBtu |
Volumes |
Average Price per
MMBtu |
NWPL |
5,700,000 |
($0.08) |
12,000,000 |
($0.13) |
NGPL |
400,000 |
($0.10) |
480,000 |
($0.15) |
SoCal |
400,000 |
$0.29 |
240,000 |
$0.19 |
San Juan |
400,000 |
($0.06) |
480,000 |
($0.12) |
WAHA |
1,150,000 |
($0.06) |
6,000,000 |
($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 for the quarter ended June 30, 2014,
which we plan to file on or about August 1, 2014.
Conference Call
As announced on July 22, 2014, Legacy will host an investor
conference call to discuss Legacy's results on Thursday, July 31,
2014 at 9:00 a.m. (Central Time). Those wishing to participate in
the conference call should dial 877-266-0479. A replay of the call
will be available through Thursday, August 7, 2014, by dialing
855-859-2056 or 404-537-3406 and entering replay code
74817855. 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, Mid-Continent and Rocky Mountain 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 June 30, |
Six Months Ended
June 30, |
|
2014 |
2013 |
2014 |
2013 |
|
(In thousands, except
per unit data) |
Revenues: |
|
|
|
|
Oil sales |
$ 108,731 |
$ 97,852 |
$ 210,786 |
$ 188,209 |
Natural gas liquids (NGL)
sales |
5,103 |
3,161 |
9,069 |
6,503 |
Natural gas sales |
23,280 |
17,373 |
43,163 |
32,553 |
|
|
|
|
|
Total revenues |
137,114 |
118,386 |
263,018 |
227,265 |
|
|
|
|
|
Expenses: |
|
|
|
|
Oil and natural gas
production |
45,809 |
37,184 |
88,343 |
72,535 |
Production and other taxes |
8,595 |
6,771 |
16,550 |
13,698 |
General and administrative |
14,809 |
7,064 |
22,456 |
13,346 |
Depletion, depreciation,
amortization and accretion |
38,537 |
39,113 |
72,234 |
80,765 |
Impairment of long-lived
assets |
2,387 |
20,774 |
3,798 |
22,517 |
Gain on disposal of assets |
(3,853) |
(46) |
(1,552) |
(265) |
|
|
|
|
|
Total expenses |
106,284 |
110,860 |
201,829 |
202,596 |
|
|
|
|
|
Operating income |
30,830 |
7,526 |
61,189 |
24,669 |
|
|
|
|
|
Other income (expense): |
|
|
|
|
Interest income |
216 |
334 |
439 |
342 |
Interest expense |
(16,225) |
(11,206) |
(30,164) |
(21,898) |
Equity in income of equity
method investees |
191 |
140 |
183 |
185 |
Net gains (losses) on commodity
derivatives |
(31,433) |
25,330 |
(47,319) |
12,325 |
Other |
211 |
(2) |
304 |
4 |
|
|
|
|
|
Income (loss) before income
taxes |
(16,210) |
22,122 |
(15,368) |
15,627 |
|
|
|
|
|
Income tax expense |
(278) |
(368) |
(592) |
(578) |
|
|
|
|
|
Net income (loss) |
$ (16,488) |
$ 21,754 |
$ (15,960) |
$ 15,049 |
Distributions to Preferred
unitholders |
(2,194) |
-- |
(2,194) |
-- |
|
|
|
|
|
Net income (loss) attributable to
unitholders |
$ (18,682) |
$ 21,754 |
$ (18,154) |
$ 15,049 |
|
|
|
|
|
Income (loss) per unit - |
|
|
|
|
basic and diluted |
$ (0.33) |
$ 0.38 |
$ (0.32) |
$ 0.26 |
|
|
|
|
|
Weighted average number of
units used in computing net income (loss) per unit - |
|
|
|
|
Basic |
57,372 |
57,246 |
57,341 |
57,162 |
|
|
|
|
|
Diluted |
57,372 |
57,349 |
57,341 |
57,195 |
|
LEGACY RESERVES
LP |
CONDENSED CONSOLIDATED
BALANCE SHEETS |
(UNAUDITED) |
|
June 30, 2014 |
December 31,
2013 |
ASSETS |
(dollars in
thousands) |
Current assets: |
|
|
Cash |
$ 10,139 |
$ 2,584 |
Accounts receivable, net: |
|
|
Oil and natural gas |
66,322 |
47,429 |
Joint interest owners |
25,454 |
16,532 |
Other |
721 |
626 |
Fair value of derivatives |
823 |
3,801 |
Prepaid expenses and other
current assets |
6,076 |
3,727 |
Total current assets |
109,535 |
74,699 |
Oil and natural gas properties using the
successful efforts method, at cost: |
|
|
Proved properties |
2,819,660 |
2,265,788 |
Unproved properties |
81,511 |
58,392 |
Accumulated depletion,
depreciation, amortization and impairment |
(857,983) |
(788,751) |
|
2,043,188 |
1,535,429 |
|
|
|
Other property and equipment, net of
accumulated depreciation and amortization of $6,368 and $6,053,
respectively |
3,573 |
3,688 |
Deposits on pending acquisitions |
5,800 |
-- |
Operating rights, net of amortization of
$4,145 and $4,024, respectively |
2,750 |
2,992 |
Fair value of derivatives |
3,158 |
21,292 |
Other assets, net of amortization of $10,652
and $10,097, respectively |
25,181 |
17,641 |
Investments in equity method investees |
3,146 |
4,092 |
Total assets |
$ 2,196,331 |
$ 1,659,833 |
LIABILITIES AND PARTNERS'
EQUITY |
|
Current liabilities: |
|
|
Accounts payable |
$ 13,093 |
$ 6,016 |
Accrued oil and natural gas
liabilities |
83,596 |
63,161 |
Fair value of derivatives |
24,008 |
10,060 |
Asset retirement
obligation |
2,610 |
2,610 |
Other |
14,203 |
12,043 |
Total current liabilities |
137,510 |
93,890 |
Long-term debt |
1,153,687 |
878,693 |
Asset retirement obligation |
219,188 |
173,176 |
Fair value of derivatives |
3,331 |
2,119 |
Other long-term liabilities |
1,635 |
1,559 |
Total liabilities |
1,515,351 |
1,149,437 |
Total partners' equity |
680,980 |
510,396 |
Total liabilities and partners' equity |
$ 2,196,331 |
$ 1,659,833 |
|
LEGACY RESERVES
LP |
SELECTED FINANCIAL AND
OPERATING DATA |
|
|
Three Months
Ended June 30, |
Six Months Ended
June 30, |
|
2014 |
2013 |
2014 |
2013 |
|
(In thousands, except
per unit data) |
Revenues: |
|
|
|
|
Oil sales |
$ 108,731 |
$ 97,852 |
$ 210,786 |
$ 188,209 |
Natural gas liquids (NGL)
sales |
5,103 |
3,161 |
9,069 |
6,503 |
Natural gas sales |
23,280 |
17,373 |
43,163 |
32,553 |
|
|
|
|
|
Total revenues |
$ 137,114 |
$ 118,386 |
$ 263,018 |
$ 227,265 |
|
|
|
|
|
Expenses: |
|
|
|
|
Oil and natural gas
production |
$ 42,056 |
$ 34,265 |
$ 81,694 |
$ 66,650 |
Ad valorem taxes |
3,753 |
2,919 |
6,649 |
5,886 |
|
|
|
|
|
Total oil and natural gas
production including ad valorem taxes |
$ 45,809 |
$ 37,184 |
$ 88,343 |
$ 72,536 |
|
|
|
|
|
Production and other taxes |
$ 8,595 |
$ 6,771 |
$ 16,550 |
$ 13,698 |
|
|
|
|
|
General and administrative
excluding LTIP |
$ 12,669 |
$ 5,721 |
$ 19,626 |
$ 11,017 |
LTIP expense |
2,140 |
1,343 |
2,830 |
2,329 |
|
|
|
|
|
Total general and
administrative |
$ 14,809 |
$ 7,064 |
$ 22,456 |
$ 13,346 |
|
|
|
|
|
Depletion, depreciation,
amortization and accretion |
$ 38,537 |
$ 39,113 |
$ 72,234 |
$ 80,765 |
|
|
|
|
|
Net cash settlements on commodity
derivatives: |
|
|
|
|
Net cash settlements (paid)
received on oil derivatives |
$ (6,244) |
$ (1,934) |
$ (8,800) |
$ (1,705) |
Net cash settlements (paid)
received on natural gas derivatives |
$ 234 |
$ 584 |
$ (820) |
$ 2,990 |
|
|
|
|
|
Production: |
|
|
|
|
Oil (MBbls) |
1,175 |
1,089 |
2,310 |
2,203 |
Natural gas liquids (MGal) |
5,519 |
3,320 |
8,881 |
6,213 |
Natural gas (MMcf) |
4,877 |
3,649 |
8,102 |
7,194 |
Total (MBoe) |
2,119 |
1,776 |
3,872 |
3,550 |
Average daily production
(Boe/d) |
23,286 |
19,516 |
21,392 |
19,613 |
|
|
|
|
|
Average sales price
per unit (excluding net cash settlements on commodity
derivatives): |
|
|
|
|
Oil price (per Bbl) |
$ 92.54 |
$ 89.85 |
$ 91.25 |
$ 85.43 |
Natural gas liquids price (per
Gal) |
$ 0.92 |
$ 0.95 |
$ 1.02 |
$ 1.05 |
Natural gas price (per
Mcf) |
$ 4.77 |
$ 4.76 |
$ 5.33 |
$ 4.53 |
Combined (per Boe) |
$ 64.71 |
$ 66.66 |
$ 67.93 |
$ 64.02 |
|
|
|
|
|
Average sales price
per unit (including net cash settlements on commodity
derivatives): |
|
|
|
|
Oil price (per Bbl) |
$ 87.22 |
$ 88.08 |
$ 87.44 |
$ 84.66 |
Natural gas liquids price (per
Gal) |
$ 0.92 |
$ 0.95 |
$ 1.02 |
$ 1.05 |
Natural gas price (per
Mcf) |
$ 4.82 |
$ 4.92 |
$ 5.23 |
$ 4.94 |
Combined (per Boe) |
$ 61.87 |
$ 65.90 |
$ 65.44 |
$ 64.38 |
|
|
|
|
|
Average NYMEX oil index prices per Bbl: |
$ 103.35 |
$ 94.05 |
$ 101.05 |
$ 94.18 |
|
|
|
|
|
Average NYMEX natural gas index prices per
Mcf: |
$ 4.68 |
$ 3.34 |
$ 4.81 |
$ 3.72 |
|
|
|
|
|
Average unit costs per Boe: |
|
|
|
|
Oil and natural gas
production |
$ 19.85 |
$ 19.29 |
$ 21.10 |
$ 18.77 |
Ad valorem taxes |
$ 1.77 |
$ 1.64 |
$ 1.72 |
$ 1.66 |
Production and other taxes |
$ 4.06 |
$ 3.81 |
$ 4.27 |
$ 3.86 |
General and administrative
excluding LTIP |
$ 5.98 |
$ 3.22 |
$ 5.07 |
$ 3.10 |
Total general and
administrative |
$ 6.99 |
$ 3.98 |
$ 5.80 |
$ 3.76 |
Depletion, depreciation,
amortization and accretion |
$ 18.19 |
$ 22.02 |
$ 18.66 |
$ 22.75 |
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, which is the amount to be distributed to our limited
partners 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 earned 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 expenses related to acquisitions.
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 June 30, |
Six Months Ended
June 30, |
|
2014 |
2013 |
2014 |
2013 |
|
(dollars in thousands) |
Net income (loss) |
$ (16,488) |
$ 21,754 |
$ (15,960) |
$ 15,049 |
Plus: |
|
|
|
|
Interest expense |
16,225 |
11,206 |
30,164 |
21,898 |
Income tax expense |
278 |
368 |
592 |
578 |
Depletion, depreciation,
amortization and accretion |
38,537 |
39,113 |
72,234 |
80,765 |
Impairment of long-lived
assets |
2,387 |
20,774 |
3,798 |
22,517 |
Gain on disposal of assets |
(3,853) |
(46) |
(1,552) |
(265) |
Equity in income of equity
method investees |
(191) |
(140) |
(183) |
(185) |
Unit-based compensation
expense |
2,140 |
1,344 |
2,830 |
2,329 |
Minimum payments earned in
excess of overriding royalty interest (1) |
341 |
10 |
673 |
410 |
EBITDA applicable to equity
method investee (2) |
241 |
226 |
499 |
226 |
Net (gains) losses on commodity
derivatives |
31,433 |
(25,330) |
47,319 |
(12,325) |
Net cash settlements received
(paid) on commodity derivatives |
(6,010) |
(1,350) |
(9,620) |
1,285 |
Transaction expenses related to
acquisitions |
4,911 |
-- |
4,966 |
-- |
Adjusted EBITDA |
$ 69,951 |
$ 67,929 |
$ 135,760 |
$ 132,282 |
|
|
|
|
|
Less: |
|
|
|
|
Cash interest expense |
15,590 |
11,866 |
29,183 |
23,444 |
Cash settlements of LTIP unit
awards |
560 |
287 |
685 |
1,145 |
Estimated maintenance capital
expenditures (3) |
18,200 |
17,000 |
36,000 |
34,000 |
Distributions on Series A and
Series B preferred units |
2,193 |
-- |
2,193 |
-- |
Distributable Cash Flow
(3) |
$ 33,408 |
$ 38,776 |
$ 67,699 |
$ 73,693 |
|
|
|
|
|
Distributions Attributable to Each
Period (4) |
$ 35,178 |
$ 33,359 |
$ 69,429 |
$ 66,377 |
|
|
|
|
|
Distribution Coverage Ratio
(3)(5) |
0.95x |
1.16x |
0.98x |
1.11x |
|
(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 exisiting 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 the
aggregate cash distributions declared for the respective period and
paid by Legacy within 45 days after the end of each quarter within
such period. |
(5) We refer to the
ratio of Distributable Cash Flow over Distributions Attributable to
Each Period ("Available Cash" 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 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 and we must borrow funds or
use cash reserves established in prior periods to cover our
quarterly distributions. 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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