Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced fourth
quarter and annual results for 2014 as well as financial guidance
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 27, 2015.
A summary of selected financial information follows. For
consolidated financial statements, please see accompanying
tables.
|
Three Months Ended
December 31, |
Twelve Months Ended
December 31, |
|
2014 |
2013 |
2014 |
2013 |
|
(dollars in millions) |
Production (Boe/d) |
32,774 |
19,402 |
26,962 |
19,668 |
Revenue |
$ 119.6 |
$ 122.0 |
$ 532.3 |
$ 485.5 |
Net Loss (a) |
$ (331.5) |
$ (46.9) |
$ (283.6) |
$ (35.3) |
Adjusted EBITDA (b) |
$ 64.7 |
$ 64.2 |
$ 278.2 |
$ 273.4 |
Distributable Cash Flow (b) |
$ 24.2 |
$ 32.5 |
$ 128.1 |
$ 151.2 |
(a)
Includes non-cash impairment charges of $440.1 million and $62.4
million for the fourth quarter of 2014 and 2013, respectively, and
$448.7 million and $85.8 million for the years ended
December 31, 2014 and 2013, 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. |
2014 highlights include:
- Generated record annual production of 26,962 Boe/d up 37% from
19,668 Boe/d in 2013
- Generated record annual EBITDA of $278.2 million
- Completed $536.3 million of acquisitions including our $360.0
million acquisition of natural gas properties located in the
Piceance Basin from WPX Energy, Inc.
- Year-end proved reserves increased 59% to a record 139.0 MMBoe
(90% PDP, 50% liquids)
Management Transition
Cary D. Brown, Chairman, President and Chief Executive Officer
of Legacy Reserves GP, LLC, the general partner of Legacy, stated:
"As previously released, this is my last week as CEO. I look
forward to serving the company as I transition my role to
Chairman. While we and our industry face an uphill battle
given current commodity prices, I am extremely comforted by the
team we have put in place to navigate these difficult
waters. With our long-lived, low-decline assets, solid hedges,
and ample liquidity under our revolver, we are well positioned for
the future."
Paul T. Horne, currently Executive Vice President and Chief
Operating Officer and soon-to-be President and Chief Executive
Officer, commented, "First off, I'd like to thank Cary for all he
has done in building and leading Legacy. I'm grateful for the
opportunity that he and the Board have provided me and I look
forward to leading the organization forward. We accomplished a
great deal in 2014 and I would like to thank our employees for
their hard work. We acquired over $530 million of properties
this year including our strategic alliance with WPX. We posted
record production and EBITDA and we raised a tremendous amount of
long-term focused capital. All of these accomplishments put us
in a better position today and for that I'm thankful.
"We undoubtedly face challenging commodity prices. While
it's not fun, we've been here several times before, and we know
what to do in this environment. We are reigning in costs across the
board and we have dramatically reduced our capital budget, from
$133 million in 2014 to $30 million in 2015. We expect service
costs to fall commensurate with price and will continue to evaluate
our capital budget options throughout the year.
Legacy is also pleased to announce the appointment of Kyle M.
Hammond as Executive Vice President and Chief Operating Officer of
Legacy Reserves GP, LLC effective March 1, 2015. Prior to
joining Legacy, Mr. Hammond founded and served as President and
Chief Executive Officer of FireWheel Energy LLC ("FireWheel") since
August 2011. Prior to forming FireWheel, Mr. Hammond served as
VP of Operations for the Permian Division of XTO Energy/Exxon
from 2003 to August 2011. While there, Mr. Hammond managed the
growth of the Permian assets as well as their Alaskan operations.
Mr. Hammond earned a BS in Petroleum Engineering from Texas A&M
University. Mr. Hammond currently serves on the board of
directors of Abilene Christian University and Midland Christian
School.
Mr. Horne added, "I am thrilled to have Kyle Hammond join the
team. I've known Kyle since our time together at Texas A&M and
respect the person, oilman, and Aggie engineer that he is. The
operational, management and growth experience he gained at XTO will
help us immensely at Legacy."
Credit Agreement Update
On February 23, 2015, Legacy amended the terms of its Credit
Agreement. Principle modifications include the replacement of
the Total Debt / EBITDA covenant with a maximum 2.5x Secured Debt /
EBITDA covenant and a minimum 2.5x EBITDA / Interest
covenant. The Partnership's year-end statistics for these two
covenants were 0.4x and 4.1x. Legacy also agreed to reduce its
borrowing base to $700 million from the prior $950 million. As
of February 23, 2015, Legacy had approximately $130 million of
borrowings outstanding, providing approximately $570 million of
liquidity available.
Dan Westcott, Executive Vice President and Chief Financial
Officer, commented, "I'd like to say thank you to Wells Fargo and
the rest of our 19-member bank group for their diligence and
support in helping us get this amendment executed. With our
new financial covenants, we have meaningfully increased our
effective liquidity and have greater capacity to swiftly make
accretive acquisitions in this market."
Proved Reserves
Our proved reserves by operating region as of December 31,
2014 are as follows:
Operating
Regions |
Oil (MBbls) |
Natural Gas
(MMcf) |
NGLs (MBbls) |
Total (MBoe) |
% Liquids |
% PDP |
% Total |
Permian Basin |
43,425 |
143,118 |
1,920 |
69,198 |
65.5 % |
80.0 % |
49.8 % |
Rocky Mountain |
10,252 |
254,358 |
6,918 |
59,563 |
28.8 % |
99.0 % |
42.9 % |
Mid-Continent |
3,163 |
17,483 |
3,200 |
9,277 |
68.6 % |
97.9 % |
6.7 % |
Other |
84 |
3,017 |
335 |
921 |
45.5 % |
100.0% |
0.6 % |
Total |
56,924 |
417,976 |
12,373 |
138,959 |
49.9 % |
89.5 % |
100.0 % |
2015 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."
|
FY 2015E
Range |
|
($ in thousands unless
otherwise noted) |
Production: |
|
|
|
Oil (MBbls) |
4,640 |
- |
4,760 |
Natural gas liquids (MGal) |
43,500 |
- |
44,600 |
Natural gas (MMcf) |
36,950 |
- |
37,850 |
Total (MBoe) |
11,834 |
- |
12,130 |
Average daily production (Boe/d) |
32,422 |
- |
33,233 |
|
|
|
|
Weighted Average NYMEX
Differentials: |
|
|
|
Oil (per Bbl) |
$(8.00) |
- |
$(7.00) |
NGL realization (1) |
0.98% |
- |
1.03% |
Natural gas (per Mcf) |
$(0.20) |
- |
$(0.15) |
|
|
|
|
Expenses: |
|
|
|
Oil and natural gas production expenses
($/Boe) |
$15.30 |
- |
$16.50 |
Ad valorem and production taxes (% of
revenue) |
7.80% |
- |
8.20% |
Cash G&A expenses (2) |
$35,000 |
- |
$36,000 |
|
|
|
|
Capital expenditures: |
|
|
|
Total development capital expenditures |
$30,000 |
- |
$30,000 |
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. |
|
LEGACY RESERVES
LP |
SELECTED FINANCIAL AND
OPERATING DATA |
|
|
|
|
|
|
Three Months
Ended December 31, |
Twelve Months
Ended December 31, |
|
2014 |
2013 |
2014 |
2013 |
|
(In thousands, except
per unit data) |
Revenues |
|
|
|
|
Oil sales |
$ 80,348 |
$ 100,931 |
$ 396,774 |
$ 405,536 |
Natural gas liquids
sales |
8,002 |
3,906 |
27,483 |
14,095 |
Natural gas sales |
31,256 |
17,204 |
108,042 |
65,858 |
Total revenues |
$ 119,606 |
$ 122,041 |
$ 532,299 |
$ 485,489 |
Expenses: |
|
|
|
|
Oil and natural gas
production |
$ 53,222 |
$ 39,490 |
$ 186,750 |
$ 142,798 |
Ad valorem taxes |
1,745 |
2,953 |
12,051 |
11,881 |
Total |
$ 54,967 |
$ 42,443 |
$ 198,801 |
$ 154,679 |
Production and other
taxes |
$ 7,242 |
$ 7,425 |
$ 31,534 |
$ 29,508 |
General and administrative
excluding LTIP |
$ 8,259 |
$ 6,429 |
$ 35,185 |
$ 24,093 |
LTIP expense |
(60) |
1,200 |
3,795 |
4,814 |
Total general and
administrative |
$ 8,199 |
$ 7,629 |
$ 38,980 |
$ 28,907 |
Depletion, depreciation,
amortization and accretion |
$ 53,436 |
$ 39,933 |
$ 173,686 |
$ 158,415 |
Commodity derivative cash settlements: |
|
|
|
|
Oil derivative cash settlements
received (paid) |
$ 9,609 |
$ (4,449) |
$ (5,431) |
$ (14,160) |
Natural gas derivative cash
settlements received |
5,031 |
2,058 |
8,097 |
7,104 |
Total commodity derivative cash
settlements |
$ 14,640 |
$ (2,391) |
$ 2,666 |
$ (7,056) |
Production: |
|
|
|
|
Oil (MBbls) |
1,253 |
1,131 |
4,784 |
4,475 |
Natural gas liquids
(MGal) |
11,283 |
3,532 |
30,861 |
13,272 |
Natural gas (MMcf) |
8,966 |
3,419 |
25,936 |
14,328 |
Total (MBoe) |
3,016 |
1,785 |
9,841 |
7,179 |
Average daily production
(Boe/d) |
32,783 |
19,402 |
26,962 |
19,668 |
Average sales price per unit (excluding
commodity derivative cash settlements): |
|
|
|
|
Oil price (per Bbl) |
$ 64.12 |
$ 89.24 |
$ 82.94 |
$ 90.62 |
Natural gas liquids price (per
Gal) |
$ 0.71 |
$ 1.11 |
$ 0.89 |
$ 1.06 |
Natural gas price (per
Mcf)(a) |
$ 3.49 |
$ 5.03 |
$ 4.17 |
$ 4.60 |
Combined (per Boe) |
$ 39.66 |
$ 68.37 |
$ 54.09 |
$ 67.63 |
Average sales price per unit (including
commodity derivative cash settlements): |
|
|
|
|
Oil price (per Bbl) |
$ 71.79 |
$ 85.31 |
$ 81.80 |
$ 87.46 |
Natural gas liquids price (per
Gal) |
$ 0.71 |
$ 1.11 |
$ 0.89 |
$ 1.06 |
Natural gas price (per
Mcf)(a) |
$ 4.05 |
$ 5.63 |
$ 4.48 |
$ 5.09 |
Combined (per Boe) |
$ 44.51 |
$ 67.03 |
$ 54.36 |
$ 66.64 |
|
|
|
|
|
Average WTI oil spot price (per
Bbl) |
$ 73.20 |
$ 97.50 |
$ 92.91 |
$ 97.98 |
Average Henry Hub natural gas index price
(per Mcf) |
$ 3.83 |
$ 3.60 |
$ 4.26 |
$ 3.66 |
|
|
|
|
|
Average unit costs per Boe: |
|
|
|
|
Production costs, excluding
production and other taxes |
$ 17.65 |
$ 22.12 |
$ 18.98 |
$ 19.89 |
Ad valorem taxes |
$ 0.58 |
$ 1.65 |
$ 1.22 |
$ 1.65 |
Production and other
taxes |
$ 2.40 |
$ 4.16 |
$ 3.20 |
$ 4.11 |
General and administrative
excluding LTIP |
$ 2.74 |
$ 3.60 |
$ 3.58 |
$ 3.36 |
Total general and
administrative |
$ 2.72 |
$ 4.27 |
$ 3.96 |
$ 4.03 |
Depletion, depreciation,
amortization and accretion |
$ 17.72 |
$ 22.37 |
$ 17.65 |
$ 22.07 |
Annual Financial and Operating Results - 2014 Compared
to 2013
- Production increased 37% to an annual record of 26,962 Boe/d
from 19,668 Boe/d primarily due to $536.3 million of acquisitions
in 2014 including our $360.0 million 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"). Additionally, production was positively impacted by
our record $133.4 million of development capital expenditures
during 2014.
- Average realized price, excluding net cash settlements from
commodity derivatives, decreased 20% to $54.09 per Boe in 2014 from
$67.63 per Boe in 2013. This decrease in realized prices was
primarily driven by the increase of NGL and natural gas production
as a percentage of total production. For instance, in 2014 NGLs and
natural gas accounted for approximately 51% of our total production
compared to approximately 38% in 2013. This increase in lower
priced production reduced our total price realization. Average
realized oil price decreased 8% to $82.94 in 2014 from $90.62 in
2013. This decrease was primarily driven by a decrease in the
average West Texas Intermediate ("WTI") crude oil price of $5.07
per Bbl as well as an increase in realized differentials, primarily
in the Permian Basin. Average natural gas price decreased 9% to
$4.17 per Mcf in 2014 from $4.60 per Mcf in 2013. While the average
Henry Hub natural gas index price increased $0.60 per Mcf, this
increase was more than offset by the inclusion of approximately
11,767 MMcf of lower priced natural gas production from the WPX
Acquisition. Finally, our average realized NGL price decreased 16%
to $0.89 per gallon in 2014 from $1.06 per gallon in 2013. This
decrease is due to the inclusion of lower priced NGL production
from the WPX Acquisition. The large majority of our separately
reported NGL production is from the properties acquired in the WPX
Acquisition and our Mid-Continent region.
- Production expenses, excluding ad valorem taxes, increased 31%
to $186.8 million in 2014 from $142.8 million in 2013. On an
average cost per Boe basis, production expenses decreased 5% to
$18.98 per Boe in 2014 from $19.89 per Boe in 2013, driven
primarily by the inclusion of lower cost natural gas properties
acquired in the WPX Acquisition.
- Non-cash impairment expense totaled $448.7 million driven by
the significant decline in oil and natural gas prices during the
fourth quarter of 2014.
- General and administrative expenses, excluding unit-based
Long-Term Incentive Plan ("LTIP") compensation expense totaled
$35.2 million in 2014 compared to $24.1 million in 2013. This
increase was primarily due to $4.5 million of increased
acquisition-related expenses and a $3.4 million increase in salary
and benefit expenses.
- Cash settlements received on our commodity derivatives during
2014 were $2.7 million, as the $8.1 million received on our natural
gas hedges was partially offset by $5.4 million paid on our crude
oil hedges. Comparably, in 2013 we paid cash settlements on our
commodity derivatives of approximately $7.1 million.
- Total development capital expenditures increased to $133.4
million in 2014 from $94.0 million in 2013, as we continued our
one-rig Wolfberry program throughout 2014, drilled four horizontal
Bone Spring wells, incurred capital costs related to our CO2
injection on properties acquired during 2014 and increased our
other operated and non-operated drilling and capital workover
activities, most of which were in the Permian Basin. Our
non-operated capital expenditures were 28% of our total capital
expenditures in 2014 as compared to 27% in 2013.
Financial and Operating Results - Fourth Quarter 2014
Compared to Fourth Quarter 2013
- Production increased 69% to 32,772 Boe/d from 19,402 Boe/d
primarily due to the WPX Acquisition and other recent acquisitions.
- Average realized price, excluding net cash settlements from
commodity derivatives, decreased 42% to $39.67 per Boe in 2014 from
$68.37 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 decreased 28% to
$64.18 per Bbl in 2014 from $89.24 per Bbl in 2013. This decrease
of $25.06 was primarily attributable to the sharp decline in the
average WTI crude oil price of $24.30 combined with slightly higher
realized regional differentials. Average realized natural gas
prices declined 31% to $3.49 per Mcf in 2014 from $5.03 per Mcf in
2013. While the average Henry Hub natural gas price index increased
by $0.23 per Mcf in 2014, this increase was more than offset by
lower realized natural gas prices from natural gas production
associated with the properties acquired in the WPX Acquisition.
Finally, our average realized NGL price decreased 36% to $0.71 per
gallon in 2014 from $1.11 per gallon in 2013 which was attributable
to the lower priced production from the WPX Acquisition.
- Production expenses, excluding ad valorem taxes, increased 35%
to $53.2 million in 2014 from $39.5 million in 2013. Production
expenses increased primarily due to expenses associated with our
acquisitions, including $11.0 million related to the WPX
Acquisition and, to a lesser extent, industry-wide cost increases.
On a per Boe basis, production expenses decreased from $22.12 to
$17.65 or 20% 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 $440.1 million due to the
significant decline of oil and natural gas prices during the
period.
- General and administrative expenses, excluding LTIP
compensation expense, increased to $8.3 million in 2014 from $6.4
million in 2013. 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.
- Cash settlements received on our commodity derivatives were
$14.6 million during 2014 compared to cash settlements paid of $2.4
million in 2013, a reflection of the sharp decline in commodity
prices during the fourth quarter of 2014. Additionally, as our
crude oil derivatives settle one-month in arrears, we incurred a
hedge-lag effect of approximately $10.5 million.
- Total development capital expenditures were $42.0 million in
the fourth quarter of 2014. Non-operated capital expenditures
comprised 39% 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 25,
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:
Calendar Year |
Volumes (Bbls) |
Average Price per
Bbl |
Price Range per
Bbl |
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:
Calendar Year |
Volumes (Bbls) |
Average Short Put Price per
Bbl |
Average Long Put Price per
Bbl |
Average Short Call Price per
Bbl |
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:
Calendar Year |
Volumes (Bbls) |
Average Short Put Price per
Bbl |
Average Swap Price per
Bbl |
2015 |
868,000 |
$76.59 |
$93.68 |
Calendar Year |
Volumes (Bbls) |
Average Long Put Price per
Bbl |
Average Short Put Price per
Bbl |
Average Swap 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 |
2015 |
1,997,000 |
($2.02) |
($1.65) |
- |
($2.55) |
Natural Gas Swaps (Henry Hub, Waha and CIG-Rockies):
Calendar Year |
Volumes (MMBtu) |
Average Price per
MMBtu |
Price Range per MMBtu |
2015 |
18,619,300 |
$4.39 |
$3.98 |
- |
$5.82 |
2016 |
1,419,200 |
$4.30 |
$4.12 |
- |
$5.30 |
Natural Gas 3-Way Collars (Henry Hub):
Calendar Year |
Volumes
(MMBtu) |
Average Short Put Price per
MMBtu |
Average Long Put Price per
MMBtu |
Average Short Call Price per
MMBtu |
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):
|
2015 |
|
Volumes (MMBtu) |
Average Price per
MMBtu |
NWPL |
12,000,000 |
$(0.13) |
NGPL |
480,000 |
$(0.15) |
SoCal |
240,000 |
$0.19 |
San Juan |
480,000 |
$(0.12) |
WAHA |
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.
Annual Report on Form 10-K
Our consolidated, audited financial statements and related
footnotes will be available in our annual 2014 Form 10-K which will
be filed on or about February 27, 2015.
Conference Call
As announced on January 23, 2015, Legacy will host an investor
conference call to discuss Legacy's results on Thursday, February
26, 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, March 5, 2015, by dialing
855-859-2056 or 404-537-3406 and entering replay code 70464452.
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 December 31, |
Twelve Months
Ended December 31, |
|
2014 |
2013 |
2014 |
2013 |
|
(In thousands, except
per unit data) |
Revenues: |
|
|
|
|
Oil sales |
$ 80,348 |
$ 100,931 |
$ 396,774 |
$ 405,536 |
Natural gas liquids (NGL)
sales |
8,002 |
3,906 |
27,483 |
14,095 |
Natural gas sales |
31,256 |
17,204 |
108,042 |
65,858 |
Total revenues |
119,606 |
122,041 |
532,299 |
485,489 |
Expenses: |
|
|
|
|
Oil and natural gas
production |
54,967 |
42,443 |
198,801 |
154,679 |
Production and other
taxes |
7,242 |
7,425 |
31,534 |
29,508 |
General and
administrative |
8,199 |
7,629 |
38,980 |
28,907 |
Depletion, depreciation,
amortization and accretion |
53,436 |
39,933 |
173,686 |
158,415 |
Impairment of long-lived
assets |
440,130 |
62,405 |
448,714 |
85,757 |
(Gain) loss on disposal of
assets |
756 |
86 |
(2,479) |
579 |
Total expenses |
564,730 |
159,921 |
889,236 |
457,845 |
Operating income
(loss) |
(445,124) |
(37,880) |
(356,937) |
27,644 |
Other income (expense): |
|
|
|
|
Interest income |
211 |
207 |
873 |
776 |
Interest
expense |
(17,971) |
(13,985) |
(67,218) |
(50,089) |
Equity in income of equity
method investees |
119 |
203 |
428 |
559 |
Net gains (losses) on commodity
derivatives |
129,417 |
4,568 |
138,092 |
(13,531) |
Other |
120 |
29 |
258 |
18 |
Income (loss) before income
taxes |
(333,228) |
(46,858) |
(284,504) |
(34,623) |
Income tax (expense) benefit |
1,729 |
(41) |
859 |
(649) |
Net income (loss) |
$ (331,499) |
$ (46,899) |
$ (283,645) |
$ (35,272) |
Distributions to preferred
unitholders |
(4,750) |
— |
(11,694) |
— |
Net income (loss) attributable
to unitholders |
$ (336,249) |
$ (46,899) |
$ (295,339) |
$ (35,272) |
Income (loss) per unit — basic
and diluted |
$ (4.94) |
$ (0.82) |
$ (4.92) |
$ (0.62) |
Weighted average number of
units used in |
|
|
|
|
computing income (loss) per
unit — |
|
|
|
|
Basic |
68,035 |
57,280 |
60,053 |
57,220 |
Diluted |
68,035 |
57,280 |
60,053 |
57,220 |
|
LEGACY RESERVES
LP |
CONDENSED CONSOLIDATED
BALANCE SHEETS |
(UNAUDITED) |
|
|
|
|
December
31, |
|
2014 |
2013 |
|
(In
thousands) |
ASSETS |
|
|
Current assets: |
|
|
Cash |
$ 725 |
$ 2,584 |
Accounts receivable, net: |
|
|
Oil and natural gas |
49,390 |
47,429 |
Joint interest
owners |
16,235 |
16,532 |
Other |
237 |
626 |
Fair value of
derivatives |
120,305 |
3,801 |
Prepaid expenses and other
current assets |
5,362 |
3,727 |
Total current assets |
192,254 |
74,699 |
Oil and natural gas properties, at cost: |
|
|
Proved oil and natural gas
properties using the successful efforts method of
accounting |
2,946,820 |
2,265,788 |
Unproved properties |
47,613 |
58,392 |
Accumulated depletion,
depreciation, amortization and impairment |
(1,354,459) |
(788,751) |
|
1,639,974 |
1,535,429 |
Other property and equipment, net of
accumulated depreciation and amortization of $7,446 and $6,053,
respectively |
3,767 |
3,688 |
Operating rights, net of amortization of
$4,509 and $4,024, respectively |
2,508 |
2,992 |
Fair value of derivatives |
32,794 |
21,292 |
Other assets, net of amortization of $12,551
and $10,097, respectively |
24,255 |
17,641 |
Investments in equity method
investees |
3,054 |
4,092 |
Total assets |
$ 1,898,606 |
$ 1,659,833 |
LIABILITIES AND PARTNERS'
EQUITY |
|
|
Current liabilities: |
|
|
Accounts payable |
$ 2,787 |
$ 6,016 |
Accrued oil and natural gas
liabilities |
78,615 |
63,161 |
Fair value of
derivatives |
2,080 |
10,060 |
Asset retirement
obligation |
3,028 |
2,610 |
Other |
11,066 |
12,043 |
Total current
liabilities |
97,576 |
93,890 |
Long-term debt |
938,876 |
878,693 |
Asset retirement obligation |
223,497 |
173,176 |
Fair value of derivatives |
— |
2,119 |
Other long-term liabilities |
1,452 |
1,559 |
Total liabilities |
1,261,401 |
1,149,437 |
Commitments and contingencies |
|
|
Partners' equity: |
|
|
Series A Preferred equity -
2,300,000 units issued and outstanding at December 31,
2014 |
55,192 |
— |
Series B Preferred equity -
7,200,000 units issued and outstanding at December 31,
2014 |
174,261 |
— |
Incentive distribution equity -
100,000 units issued and outstanding at December 31,
2014 |
30,814 |
— |
Limited partners' equity -
68,910,784 and 57,280,049 units issued and outstanding at December
31, 2014 and 2013, respectively |
376,885 |
510,322 |
General partner's equity
(approximately 0.03%) |
53 |
74 |
Total partners'
equity |
637,205 |
510,396 |
Total liabilities and partners'
equity |
$ 1,898,606 |
$ 1,659,833 |
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 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 December 31, |
Twelve Months
Ended December 31, |
|
2014 |
2013 |
2014 |
2013 |
|
(In
thousands) |
Net income (loss) |
$ (331,499) |
$ (46,899) |
$ (283,645) |
$ (35,272) |
Plus: |
|
|
|
|
Interest expense |
17,971 |
13,985 |
67,218 |
50,089 |
Income tax expense
(benefit) |
(1,729) |
41 |
(859) |
649 |
Depletion, depreciation,
amortization and accretion |
53,436 |
39,933 |
173,686 |
158,415 |
Impairment of long-lived
assets |
440,130 |
62,405 |
448,714 |
85,757 |
(Gain) loss on disposal of
assets |
756 |
86 |
(2,479) |
579 |
Equity in income of equity
method investees |
(119) |
(203) |
(428) |
(559) |
Unit-based compensation
expense |
(60) |
1,200 |
3,795 |
4,814 |
Minimum payments received in
excess of overriding royalty interest earned(1) |
358 |
325 |
1,381 |
1,051 |
Equity in EBITDA of equity
method investee(2) |
156 |
282 |
805 |
727 |
Net (gains) losses on commodity
derivatives |
(129,417) |
(4,568) |
(138,092) |
13,531 |
Net cash settlements received
(paid) on commodity derivatives |
14,640 |
(2,391) |
2,666 |
(7,056) |
Transaction expenses related to
acquisitions |
95 |
35 |
5,425 |
722 |
Adjusted EBITDA |
$ 64,718 |
$ 64,231 |
$ 278,187 |
$ 273,447 |
|
|
|
|
|
Less: |
|
|
|
|
Cash interest
expense |
17,597 |
13,918 |
65,236 |
51,171 |
Cash settlements of LTIP unit
awards |
1 |
36 |
772 |
1,496 |
Estimated maintenance capital
expenditures(3) |
18,200 |
17,800 |
72,400 |
69,600 |
Distributions on Series A and
Series B preferred units |
4,750 |
— |
11,694 |
— |
Distributable Cash
Flow(3) |
$ 24,170 |
$ 32,477 |
$ 128,085 |
$ 151,180 |
|
|
|
|
|
Distributions Attributable to Each
Period(4) |
$ 42,208 |
$ 33,934 |
$ 153,829 |
$ 133,956 |
|
|
|
|
|
Distribution Coverage
Ratio(3)(5) |
0.57x |
0.96x |
0.83x |
1.13x |
(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 to our unitholders 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"
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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