Legacy Reserves LP ("Legacy") (NASDAQ:LGCY) today announced first
quarter results for 2016 including the following Q1 highlights:
- Increased production to 45,527 Boe/d
- Reduced lease operating expenses, excluding ad valorem taxes,
of $46.7 million representing a nearly 4% decrease compared to Q4
2015
- Closed $68.5 million of asset sales, above our
previously-announced target of $50 million
- Reduced debt outstanding by $191.8 million including a $38.0
million reduction in borrowings under our credit facility and
$153.8 million of senior notes
- Reported net income of $105.3 million, representing earnings
per unit of $1.47 driven by a gain on extinguishment of debt of
$130.8 million
Operational Update
During Q1 2016 we spent $4.8 million of our $37
million 2016 capital budget representing 13% of the annual total.
Approximately 20% was spent on recompletions and workovers in our
East Texas region. The vast majority of the balance was deployed in
the Permian on workovers and on horizontal development under our
development agreement with an affiliate of TPG Special Situations
Partners (“TSSP”) under which we operate all wells and fund 5% of
the parties' development capital. Since September 2015 we have
drilled and completed 12 horizontal wells under the program: 5 in
Lea County, NM, 1 in Southern Reagan County, TX and 6 in Howard
County, TX. Based on current strip pricing, we anticipate
that our 2016 capital expenditures will be less than our initial
$37 million capital budget. We do not maintain any long-term
drilling contracts and serve as operator of approximately 90% of
our anticipated capital program. Accordingly, we maintain
significant control of the capital program budget and may deviate
materially from the figures above based on market conditions (or
otherwise) with the overriding intent to deploy capital
prudently.
2016 Asset Sales Update
During Q1 2016, we closed seven divestitures
generating net proceeds of $68.5 million. Below are the summary
statistics of such sales:
Transaction Statistics:
Total Sales Price |
|
$ |
68,459,288 |
|
Transaction Count |
|
7 |
|
County Count |
|
12 |
|
Total Net Acreage |
|
13,225 |
|
Midland Basin Net Acreage (1) |
|
5,469 |
|
% of Year-End 2015 Midland Basin
Acreage (1) |
|
28 |
% |
Average Gross Midland Basin Tract
Size (acres) |
|
233 |
|
Q4 2015 Production (Boe/d) |
|
521 |
|
Cash Flow (2) |
|
$ |
1,902,194 |
|
Total Gross Well Count |
|
129 |
|
YE 2015 PUDs |
|
1 |
|
Multiple of Cash Flow |
|
36.0x |
$ / Net Midland Basin Acre (3) |
|
$ |
11,789 |
|
|
|
|
|
|
______________________
(1) Excludes our and TSSP's combined interests in approximately
4,092 net acres in the Midland Basin committed to the parties'
development agreement.
(2) Estimate based on last twelve months prior to closing each
transaction.
(3) Calculated as sales price received attributable to Midland
Basin acreage divided by Midland Basin acreage.
In April, we completed four additional
divestments for approximately $5.4 million, which brings our year
to date percent of year-end 2015 Midland Basin acreage divested to
35%. We are continuing to pursue a few other select opportunities
with the aim to complete a total of $100 million of asset sales
during the first half of 2016.
Capital Structure Update
Through May 4, 2016, we have utilized a portion
of the proceeds from asset sales to repurchase a total of $169.4
million of our senior notes in the open market. Our debt balances
as of each of the respective dates are as follows:
|
|
12/31/2015 |
3/31/2016 |
5/4/2016 |
|
|
(In thousands) |
Credit Facility due
2019 |
|
$ |
608,000 |
|
$ |
570,000 |
|
$ |
560,000 |
|
8% Senior Notes
(1) |
|
300,000 |
|
255,570 |
|
247,989 |
|
6.625% Senior Notes
(1) |
|
550,000 |
|
440,661 |
|
432,656 |
|
Total Debt Outstanding
(1) |
|
$ |
1,458,000 |
|
$ |
1,266,231 |
|
$ |
1,240,645 |
|
______________________
(1) Excludes unamortized discount on Senior
Notes.
On May 4, 2016, as a result of the scheduled
spring redetermination process, our borrowing base under our
revolving credit facility was redetermined to $630 million, down
from $725 million as set in February. With outstanding borrowings
of $560 million and $1.4 million of outstanding letters of credit,
we currently have $68.6 million of availability.
Near-Term Outlook and
Commentary
Paul T. Horne, President and Chief Executive
Officer of Legacy's general partner commented, “Q1 represented our
lowest realized pricing in our company history at $15.90 per Boe,
or 34% and 71% lower than our 2015 and 2014 realized pricing on a
per Boe basis, respectively. Despite this difficult
challenge, our team continues to make meaningful operational
improvements. LOE was down 4% from last quarter and down 19% on a
comparable basis to Q1 2015 while G&A excluding LTIP and
transaction related expenses was down 10% relative to last quarter.
We remain incredibly disciplined with our capital spending, as
during the quarter we only spent 13% of our previously announced
annual budget, and now expect our capital expenditures to be lower
for 2016. We are pleased with our initial results on our East Texas
recompletion efforts and anticipate dedicating more capital to this
effort. We are very pleased with our results to date under our
horizontal Permian development program with TSSP, having beat our
estimated drilling and completion costs by 19% driven by a 39%
improvement in estimated drilling days while achieving very
encouraging early production rates. Despite funding only 5% of the
development capital net to our combined interests under this
program, we generated 567 Boe/d of net production in the quarter.
We are currently evaluating the resumption of the development
program which could potentially occur in early Q3 2016.
“The recent rise in commodity prices has
certainly been helpful to Legacy and the energy industry as a
whole. However, given the gravity of the price depression relative
to prior years, we are still operating in a highly challenging
environment. Our focus for at least the remainder of the year will
be to continue to maintain liquidity and reduce our debt
outstanding and therefore we have no near-term plans to resume our
distributions on either our preferred units or common units. As
always, we will continue to closely watch the market and respond
with business objectives that match accordingly.”
Dan Westcott, Executive Vice President and Chief
Financial Officer of Legacy's general partner commented, “We were
able to make significant strides on improving our balance sheet
during the quarter. The approximately $69 million of asset sales
closed in Q1 have generated liquidity, reduced future plugging
obligations, and improved our leverage statistics. Since the
beginning of the year, we have used $21.5 million to repurchase
$169.4 million of our senior notes, reflecting a projected cash
interest savings of $11.9 million per year. In total, we have
reduced our debt outstanding by $217.4 million since year-end. Our
recently redetermined borrowing base of $630 million certainly
narrows our liquidity and, given our earlier credit agreement
amendment, prohibits any cash distributions on our preferred units
and common units given our Total Debt / EBITDA currently exceeds
4.0x, and prohibits Senior Notes repurchases given we no longer
meet the required minimum liquidity levels. However, in the final
three quarters of the year, we currently project to generate
$15-$20 million of free cash flow (excluding asset sales) from
approximately 44.2 mboe/d of production, with differentials and
lifting costs consistent with prior periods, and believe our
current liquidity position is sustainable to run the business for
the foreseeable future. We recognize that we have additional levers
available to us, whether those are further asset sales, financings
or otherwise and will pull such levers if needed based upon the
financial and commodity markets presented. Our goals remain
to continue to improve our balance sheet and position Legacy for
success.”
Ongoing Proxy Process
We are currently seeking the vote of all
unitholders through our 2016 proxy process. Our proxy can be found
at: http://ir.legacylp.com/proxy.cfm. If you have lost your voting
instructions or if you have questions about the voting process,
please do not hesitate to contact our proxy solicitor, Morrow &
Co., toll free at 800-662-5200. Every vote is important and we
strongly encourage you to vote your units.
LEGACY RESERVES LP |
SELECTED FINANCIAL AND OPERATING
DATA |
|
|
|
Three Months Ended |
|
|
March 31, |
|
|
2016 |
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
(In thousands, except per unit
data) |
Revenues: |
|
|
|
|
Oil sales |
|
$ |
30,320 |
|
|
$ |
50,296 |
|
Natural gas liquids sales |
|
2,453 |
|
|
4,192 |
|
Natural gas sales |
|
33,086 |
|
|
27,051 |
|
Total revenue |
|
$ |
65,859 |
|
|
$ |
81,539 |
|
Expenses: |
|
|
|
|
Oil and natural gas production,
excluding ad valorem taxes |
|
$ |
46,661 |
|
|
$ |
45,944 |
|
Ad valorem taxes |
|
$ |
3,362 |
|
|
$ |
3,276 |
|
Total oil and natural gas
production |
|
$ |
50,023 |
|
|
$ |
49,220 |
|
Production and other taxes |
|
$ |
2,573 |
|
|
$ |
4,218 |
|
General and administrative,
excluding transaction related costs and LTIP |
|
$ |
7,692 |
|
|
$ |
7,756 |
|
Transaction related costs |
|
$ |
77 |
|
|
$ |
25 |
|
LTIP expense |
|
$ |
1,665 |
|
|
$ |
1,088 |
|
Total general and
administrative |
|
$ |
9,434 |
|
|
$ |
8,869 |
|
Depletion, depreciation,
amortization and accretion |
|
$ |
36,959 |
|
|
$ |
41,068 |
|
Commodity derivative
cash settlements: |
|
|
|
|
Oil derivative cash settlements
received |
|
$ |
12,585 |
|
|
$ |
32,200 |
|
Natural gas derivative cash
settlements received |
|
$ |
10,192 |
|
|
$ |
8,137 |
|
Production: |
|
|
|
|
Oil (MBbls) |
|
1,069 |
|
|
1,200 |
|
Natural gas liquids (MGal) |
|
8,241 |
|
|
9,686 |
|
Natural gas (MMcf) |
|
17,266 |
|
|
9,658 |
|
Total (MBoe) |
|
4,143 |
|
|
3,040 |
|
Average daily production
(Boe/d) |
|
45,527 |
|
|
33,778 |
|
Average sales price per
unit (excluding derivative cash settlements): |
|
|
|
|
Oil price (per Bbl) |
|
$ |
28.36 |
|
|
$ |
41.91 |
|
Natural gas liquids price (per
Gal) |
|
$ |
0.30 |
|
|
$ |
0.43 |
|
Natural gas price (per Mcf) |
|
$ |
1.92 |
|
|
$ |
2.80 |
|
Combined (per Boe) |
|
$ |
15.90 |
|
|
$ |
26.82 |
|
Average sales price per
unit (including derivative cash settlements): |
|
|
|
|
Oil price (per Bbl) |
|
$ |
40.14 |
|
|
$ |
68.75 |
|
Natural gas liquids price (per
Gal) |
|
$ |
0.30 |
|
|
$ |
0.43 |
|
Natural gas price (per Mcf) |
|
$ |
2.51 |
|
|
$ |
3.64 |
|
Combined (per Boe) |
|
$ |
21.39 |
|
|
$ |
40.09 |
|
Average WTI oil spot
price (per Bbl) |
|
$ |
33.35 |
|
|
$ |
48.49 |
|
Average Henry Hub
natural gas index price (per Mcf) |
|
$ |
1.99 |
|
|
$ |
2.90 |
|
Average unit costs per
Boe: |
|
|
|
|
Oil and natural gas production,
excluding ad valorem taxes |
|
$ |
11.26 |
|
|
$ |
15.11 |
|
Ad valorem taxes |
|
$ |
0.81 |
|
|
$ |
1.08 |
|
Production and other taxes |
|
$ |
0.62 |
|
|
$ |
1.39 |
|
General and administrative
excluding transaction related costs and LTIP |
|
$ |
1.86 |
|
|
$ |
2.55 |
|
Total general and
administrative |
|
$ |
2.28 |
|
|
$ |
2.92 |
|
Depletion, depreciation,
amortization and accretion |
|
$ |
8.92 |
|
|
$ |
13.51 |
|
|
|
|
|
|
|
|
|
|
Financial and Operating Results - Three-Month Period
Ended March 31, 2016 Compared to Three-Month Period Ended
March 31, 2015
- Production increased 35% to 45,527 Boe/d from 33,778 Boe/d
primarily due to our 2015 acquisitions including our East Texas
acquisitions from WGR Operating LP and Anadarko E&P Onshore LLC
("Anadarko Acquisitions").
- Average realized price, excluding net cash settlements from
commodity derivatives, decreased 41% to $15.90 per Boe in 2016 from
$26.82 per Boe in 2015 driven by the significant decline in
commodity prices as well as the increase of natural gas production
as a percentage of total production. Average realized oil price
decreased 32% to $28.36 in 2016 from $41.91 in 2015 driven by a
decrease in the average West Texas Intermediate ("WTI") crude oil
price of $15.14 per Bbl partially offset by an improvement in
realized regional differentials. Average realized natural gas price
decreased 31% to $1.92 per Mcf in 2016 from $2.80 per Mcf in 2015.
This decrease is a result of the decrease in the average Henry Hub
natural gas index price of $0.91 per Mcf. Finally, our average
realized NGL price decreased 30% to $0.30 per gallon in 2016 from
$0.43 per gallon in 2015.
- Production expenses, excluding ad valorem taxes, increased 2%
to $46.7 million in 2016 from $45.9 million in 2015, primarily due
to production expenses related to our acquisition of East Texas
properties ($9.2 million) partially offset by cost reduction
efforts on our historical properties. On an average cost per Boe
basis, production expenses excluding ad valorem taxes decreased 25%
to $11.26 per Boe in 2016 from $15.11 per Boe in 2015, driven
primarily by the inclusion of lower cost production from our
acquired East Texas properties as well as cost reduction efforts in
our historical properties.
- General and administrative expenses, excluding unit-based
Long-Term Incentive Plan compensation expense totaled $7.8 million
in 2016, flat to 2015, reflecting cost reduction efforts offsetting
increases in salaries and wages commensurate with a larger asset
base following our acquisition of East Texas properties.
- Cash settlements received on our commodity derivatives during
2016 were $22.8 million compared to $40.3 million in 2015. While
commodity prices were lower in 2016, the decline in cash
settlements received is a result of the reduced nominal volumes
hedges in Q1 2016 compared to Q1 2015.
- Total development capital expenditures decreased to $4.8
million in 2016 from $13.4 million in 2015. The 2016 activity was
comprised mainly of the drilling and completion of joint
development agreement wells and capital costs related to CO2
properties.
- Non-cash impairment expense totaled $15.4 million due to the
continued decline in oil and natural gas futures prices.
Commodity Derivative Contracts
We enter into oil and natural gas derivative
contracts to help mitigate the risk of changing commodity prices.
As of May 2, 2016, we had entered into derivative agreements
to receive average NYMEX WTI crude oil prices and NYMEX Henry Hub,
Waha, NWPL, SoCal and San Juan natural gas prices as summarized
below.
WTI Crude Oil Swaps:
Time Period |
|
Volumes (Bbls) |
|
Average Price per Bbl |
|
Price Range per Bbl |
April-December
2016 |
|
439,900 |
|
|
$ |
67.93 |
|
|
$ |
56.15 |
|
- |
$ |
99.85 |
|
2017 |
|
182,500 |
|
|
$ |
84.75 |
|
|
$ |
84.75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI Crude Oil 3-Way Collars. At an average WTI market price of
$40.00, the summary positions below would result in a net price of
$65.00 for the remainder of 2016 and 2017:
|
|
|
|
Average Short Put |
|
Average Long Put |
|
Average Short Call |
Time Period |
|
Volumes (Bbls) |
|
Price per Bbl |
|
Price per Bbl |
|
Price per Bbl |
April-December
2016 |
|
425,650 |
|
|
$ |
62.46 |
|
|
$ |
87.46 |
|
|
$ |
105.34 |
|
2017 |
|
72,400 |
|
|
$ |
60.00 |
|
|
$ |
85.00 |
|
|
$ |
104.20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI Crude Oil Enhanced Swaps. At an average WTI market price of
$40.00, the summary positions below would result in a net price of
$66.70, $65.85 and $65.50 for the remainder of 2016, 2017 and 2018,
respectively:
|
|
|
|
Average Long Put |
|
Average Short Put |
|
Average Swap |
Time Period |
|
Volumes (Bbls) |
|
Price per Bbl |
|
Price per Bbl |
|
Price per Bbl |
April-December
2016 |
|
137,500 |
|
|
$ |
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
2016 |
|
2,200,000 |
|
|
$ |
(1.60 |
) |
|
$ |
(1.50 |
) |
- |
$ |
(1.75 |
) |
2017 |
|
2,190,000 |
|
|
$ |
(0.30 |
) |
|
$ |
(0.05 |
) |
- |
$ |
(0.75 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Swaps (Henry Hub and Waha):
|
|
|
|
Average |
|
|
|
|
Time Period |
|
Volumes (MMBtu) |
|
Price per MMBtu |
|
Price Range per MMBtu |
April-December
2016 |
|
21,746,400 |
|
|
$ |
3.40 |
|
|
$ |
3.29 |
|
- |
$ |
5.30 |
|
2017 |
|
27,600,000 |
|
|
$ |
3.36 |
|
|
$ |
3.29 |
|
- |
$ |
3.39 |
|
2018 |
|
27,600,000 |
|
|
$ |
3.36 |
|
|
$ |
3.29 |
|
- |
$ |
3.39 |
|
2019 |
|
25,800,000 |
|
|
$ |
3.36 |
|
|
$ |
3.29 |
|
- |
$ |
3.39 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas 3-Way Collars (Henry Hub). At an annual average
Henry Hub market price of $2.00, the summary positions below would
result in a net price of $2.50 for the remainder of 2016 and
2017:
|
|
Volumes |
|
Average Short Put |
|
Average Long Put |
|
Average Short Call |
Time Period |
|
(MMBtu) |
|
Price per MMBtu |
|
Price per MMBtu |
|
Price per MMBtu |
April-December
2016 |
|
4,185,000 |
|
$ |
3.75 |
|
|
$ |
4.25 |
|
|
$ |
5.08 |
|
2017 |
|
5,040,000 |
|
$ |
3.75 |
|
|
$ |
4.25 |
|
|
$ |
5.53 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Basis Swaps (NWPL, SoCal and San Juan)
|
|
April-December 2016 |
|
2017 |
|
|
|
|
Average |
|
|
|
Average |
|
|
Volumes (MMBtu) |
|
Price per MMBtu |
|
Volumes (MMBtu) |
|
Price per MMBtu |
NWPL |
|
11,253,825 |
|
$ |
(0.19 |
) |
|
7,300,000 |
|
$ |
(0.16 |
) |
SoCal |
|
— |
|
$ |
— |
|
|
2,500,250 |
|
$ |
0.11 |
|
San Juan |
|
1,878,250 |
|
$ |
(0.16 |
) |
|
2,500,250 |
|
$ |
(0.10 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Location and quality differentials attributable
to our properties are not reflected in the above prices. The
agreements provide for monthly settlement based on the difference
between the agreement fixed price and the actual reference oil and
natural gas index prices.
Quarterly Report on Form
10-Q
Financial results contained herein are
preliminary and subject to the final, unaudited financial
statements and related footnotes included in Legacy's Form 10-Q
which will be filed on or about May 4, 2016.
Conference Call
As announced on April 20, 2016, Legacy will host
an investor conference call to discuss Legacy's results on
Thursday, May 5, 2016 at 9:00 a.m. (Central Time). Those wishing to
participate in the conference call should dial 877-266-0479. A
replay of the call will be available through Thursday, May 12,
2016, by dialing 855-859-2056 or 404-537-3406 and entering replay
code 86768701. 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.
Additional Information for Holders of
Legacy Units
Although Legacy has suspended distributions to
both the 8% Series A and Series B Fixed-to-Floating Rate Cumulative
Redeemable Perpetual Preferred Units (the "Preferred Units"), such
distributions continue to accrue. Pursuant to the terms of Legacy's
partnership agreement, Legacy is required to pay or set aside for
payment all accrued but unpaid distributions with respect to the
Preferred Units prior to or contemporaneously with making any
distribution with respect to Legacy's units. Accruals of
distributions on the Preferred Units are treated for tax purposes
as guaranteed payments for the use of capital that will generally
be taxable to the holders of such Preferred Units as ordinary
income even in the absence of contemporaneous distributions.
In addition, Legacy unitholders, just like
unitholders of other master limited partnerships, are allocated
taxable income irrespective of cash distributions paid. As partners
in a partnership, unitholders are allocated a share of taxable
income irrespective of the amount of cash, if any, distributed to
the unitholders. Taxable income in a given period to a unitholder
may include ordinary income from cancellation of our debt and
capital gain upon disposition of properties and the tax allocation
of taxable income may require the payment of United States federal
income taxes and, in some cases, state and local income taxes by
our unitholders. As of January 21, 2016, Legacy has suspended all
cash distributions to unitholders and holders of the Preferred
Units. Legacy may engage in transactions to de-lever the
Partnership and manage its liquidity that may result in income and
gain to unitholders. For example, unitholders may be
allocated taxable income and gain resulting from asset sales.
Further, if Legacy engages in debt exchanges, debt repurchases, or
modifications of our existing debt, these or similar transactions
could result in “cancellation of indebtedness income” (also
referred to as “COD income”) being allocated to unitholders as
taxable income. Unitholders may be allocated gain and income from
asset sales and COD income and may owe income tax as a result of
such allocations notwithstanding the fact that we have currently
suspended cash distributions to unitholders. The ultimate effect of
any such allocations will depend on the unitholder's individual tax
position with respect to its units. Unitholders are encouraged to
consult their tax advisors with respect to the consequences of
potential transactions that may result in income and gain to
unitholders.
About Legacy Reserves LP
Legacy Reserves LP is a master limited
partnership headquartered in Midland, Texas, focused on the
acquisition and development of oil and natural gas properties
primarily located in the Permian Basin, East Texas, Rocky Mountain
and Mid-Continent regions of the United States. Additional
information is available at www.LegacyLP.com.
Cautionary Statement Relevant to
Forward-Looking Information
This press release contains forward-looking
statements relating to our operations that are based on
management's current expectations, estimates and projections about
its operations. Words such as "anticipates," "expects," "intends,"
"plans," "targets," "projects," "believes," "seeks," "schedules,"
"estimated," and similar expressions are intended to identify such
forward-looking statements. These statements are not guarantees of
future performance and are subject to certain risks, uncertainties
and other factors, some of which are beyond our control and are
difficult to predict. Among the important factors that could cause
actual results to differ materially from those in the
forward-looking statements are: realized oil and natural gas
prices; production volumes, lease operating expenses, general and
administrative costs and finding and development costs; future
operating results and the factors set forth under the heading "Risk
Factors" in our annual and quarterly reports filed with the SEC.
Therefore, actual outcomes and results may differ materially from
what is expressed or forecasted in such forward-looking statements.
The reader should not place undue reliance on these forward-looking
statements, which speak only as of the date of this press release.
Unless legally required, Legacy undertakes no obligation to update
publicly any forward-looking statements, whether as a result of new
information, future events or otherwise.
LEGACY RESERVES LP |
CONDENSED CONSOLIDATED STATEMENTS OF
OPERATIONS |
(UNAUDITED) |
|
|
|
Three Months Ended |
|
|
March 31, |
|
|
2016 |
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
(In thousands, except per unit
data) |
Revenues: |
|
|
|
|
Oil sales |
|
$ |
30,320 |
|
|
$ |
50,296 |
|
Natural gas liquids (NGL)
sales |
|
2,453 |
|
|
4,192 |
|
Natural gas sales |
|
33,086 |
|
|
27,051 |
|
Total revenues |
|
65,859 |
|
|
81,539 |
|
|
|
|
|
|
Expenses: |
|
|
|
|
Oil and natural gas production |
|
50,023 |
|
|
49,220 |
|
Production and other taxes |
|
2,573 |
|
|
4,218 |
|
General and administrative |
|
9,434 |
|
|
8,869 |
|
Depletion, depreciation,
amortization and accretion |
|
36,959 |
|
|
41,068 |
|
Impairment of long-lived
assets |
|
15,447 |
|
|
209,402 |
|
(Gain) loss on disposal of
assets |
|
(31,701 |
) |
|
1,941 |
|
Total expenses |
|
82,735 |
|
|
314,718 |
|
|
|
|
|
|
Operating loss |
|
(16,876 |
) |
|
(233,179 |
) |
|
|
|
|
|
Other income
(expense): |
|
|
|
|
Interest income |
|
38 |
|
|
206 |
|
Interest expense |
|
(25,176 |
) |
|
(17,792 |
) |
Gain on extinguishment of debt |
|
130,804 |
|
|
— |
|
Equity in income (loss) of equity
method investees |
|
(5 |
) |
|
79 |
|
Net gains on commodity
derivatives |
|
17,038 |
|
|
20,480 |
|
Other |
|
(94 |
) |
|
605 |
|
Incomes (loss) before income
taxes |
|
105,729 |
|
|
(229,601 |
) |
Income tax (expense)
benefit |
|
(400 |
) |
|
747 |
|
Net income (loss) |
|
$ |
105,329 |
|
|
$ |
(228,854 |
) |
Distributions to Preferred
unitholders |
|
(3,958 |
) |
|
(4,750 |
) |
Net income (loss) attributable to
unitholders |
|
$ |
101,371 |
|
|
$ |
(233,604 |
) |
|
|
|
|
|
Income (loss) per unit - basic and
diluted |
|
$ |
1.47 |
|
|
$ |
(3.39 |
) |
Weighted average number of units
used in computing net income (loss) per unit - |
|
|
|
|
Basic and diluted |
|
68,964 |
|
|
68,921 |
|
|
|
|
|
|
|
|
LEGACY RESERVES LP |
CONDENSED CONSOLIDATED BALANCE
SHEETS |
(UNAUDITED) |
|
ASSETS |
|
|
March 31, 2016 |
|
December 31, 2015 |
|
|
(In thousands) |
Current assets: |
|
|
|
|
Cash |
|
$ |
5,269 |
|
|
$ |
2,006 |
|
Accounts receivable, net: |
|
|
|
|
Oil and natural gas |
|
29,086 |
|
|
33,944 |
|
Joint interest owners |
|
26,796 |
|
|
25,378 |
|
Other |
|
55 |
|
|
86 |
|
Fair value of derivatives |
|
60,462 |
|
|
63,711 |
|
Prepaid expenses and other current
assets |
|
4,119 |
|
|
4,334 |
|
Total current assets |
|
125,787 |
|
|
129,459 |
|
Oil and natural gas
properties using the successful efforts method, at cost: |
|
|
|
|
Proved properties |
|
3,394,646 |
|
|
3,485,634 |
|
Unproved properties |
|
13,425 |
|
|
13,424 |
|
Accumulated depletion,
depreciation, amortization and impairment |
|
(2,081,624 |
) |
|
(2,090,102 |
) |
|
|
1,326,447 |
|
|
1,408,956 |
|
Other property and
equipment, net of accumulated depreciation and amortization of
$9,341 and $8,915, respectively |
|
4,328 |
|
|
4,575 |
|
Operating rights, net
of amortization of $5,057 and $4,953, respectively |
|
1,960 |
|
|
2,064 |
|
Fair value of
derivatives |
|
52,226 |
|
|
56,373 |
|
Other assets |
|
10,349 |
|
|
11,047 |
|
Investments in equity
method investees |
|
641 |
|
|
646 |
|
Total assets |
|
$ |
1,521,738 |
|
|
$ |
1,613,120 |
|
LIABILITIES AND PARTNERS' DEFICIT |
Current
liabilities: |
|
|
|
|
Accounts payable |
|
$ |
2,717 |
|
|
$ |
13,581 |
|
Accrued oil and natural gas
liabilities |
|
43,561 |
|
|
50,573 |
|
Fair value of derivatives |
|
2,291 |
|
|
2,019 |
|
Asset retirement obligation |
|
3,496 |
|
|
3,496 |
|
Other |
|
19,328 |
|
|
11,424 |
|
Total current liabilities |
|
71,393 |
|
|
81,093 |
|
Long-term debt |
|
1,238,073 |
|
|
1,427,614 |
|
Asset retirement
obligation |
|
281,429 |
|
|
282,909 |
|
Fair value of
derivatives |
|
2,404 |
|
|
— |
|
Other long-term
liabilities |
|
1,181 |
|
|
1,181 |
|
Total liabilities |
|
1,594,480 |
|
|
1,792,797 |
|
Commitments and
contingencies |
|
|
|
|
Partners' equity |
|
|
|
|
Series A Preferred equity -
2,300,000 units issued and outstanding at March 31, 2016 and
December 31, 2015 |
|
55,192 |
|
|
55,192 |
|
Series B Preferred equity -
7,200,000 units issued and outstanding at March 31, 2016 and
December 31, 2015 |
|
174,261 |
|
|
174,261 |
|
Incentive distribution equity -
100,000 units issued and outstanding at March 31, 2016 and December
31, 2015 |
|
30,814 |
|
|
30,814 |
|
Limited partners' deficit -
68,972,841 and 68,949,961 units issued and outstanding at March 31,
2016 and December 31, 2015, respectively |
|
(332,904 |
) |
|
(439,811 |
) |
General partner's deficit
(approximately 0.03%) |
|
(105 |
) |
|
(133 |
) |
Total partners' deficit |
|
(72,742 |
) |
|
(179,677 |
) |
Total liabilities and
partners' deficit |
|
$ |
1,521,738 |
|
|
$ |
1,613,120 |
|
|
|
|
|
|
|
|
|
|
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, |
|
2016 |
|
2015 |
|
|
|
|
|
|
|
|
|
(In thousands) |
Net income
(loss) |
$ |
105,329 |
|
|
$ |
(228,854 |
) |
Plus: |
|
|
|
Interest expense |
25,176 |
|
|
17,792 |
|
Gain on extinguishment of debt |
(130,804 |
) |
|
— |
|
Income tax expense (benefit) |
400 |
|
|
(747 |
) |
Depletion, depreciation,
amortization and accretion |
36,959 |
|
|
41,068 |
|
Impairment of long-lived
assets |
15,447 |
|
|
209,402 |
|
(Gain) loss on disposal of
assets |
(31,701 |
) |
|
1,941 |
|
Equity in income (loss) of equity
method investees |
5 |
|
|
(79 |
) |
Unit-based compensation
expense |
1,665 |
|
|
1,088 |
|
|
|
|
|
|
|
Minimum payments received in excess
of overriding royalty interest earned(1) |
802 |
|
|
367 |
|
Equity in EBITDA of equity method
investee(2) |
— |
|
|
119 |
|
Net gains on commodity
derivatives |
(17,038 |
) |
|
(20,480 |
) |
Net cash settlements received on
commodity derivatives |
22,777 |
|
|
40,337 |
|
Transaction related expenses |
77 |
|
|
25 |
|
Adjusted
EBITDA |
$ |
29,094 |
|
|
$ |
61,979 |
|
|
|
|
|
Less: |
|
|
|
Cash interest expense |
19,228 |
|
|
17,042 |
|
Development capital
expenditures(4) |
4,801 |
|
|
13,366 |
|
Distributions on Series A and
Series B preferred units |
— |
|
|
4,750 |
|
Distributable
Cash Flow(3) |
$ |
5,065 |
|
|
$ |
26,821 |
|
|
|
|
|
|
|
|
|
(1) Minimum payments received in excess of overriding royalties
earned under a contractual agreement expiring December 31, 2019.
The remaining amount of the minimum payments is recognized in net
income.(2) Equity in EBITDA of equity method investee is defined as
the equity method investee's net income or loss plus interest
expense and depreciation. We divested our interest in this investee
in May of 2015.(3) Estimated maintenance capital expenditures are
intended to represent the amount of capital required to fully
offset declines in production, but do not target specific levels of
proved reserves to be achieved. Estimated maintenance capital
expenditures do not include the cost of new oil and natural gas
reserve acquisitions, but rather the costs associated with
converting proved developed non-producing, proved undeveloped and
unproved reserves to proved developed producing reserves.
These costs, which are incorporated in our annual capital budget as
approved by the Board, include development drilling, recompletions,
workovers and various other procedures to generate new or improve
existing production on both operated and non-operated
properties. Estimated maintenance capital expenditures are
based on management's judgment of various factors including the
long-term (generally 5-10 years) decline rate of our current
production and the projected productivity of our total development
capital expenditures. Actual production decline rates and
capital efficiency may materially differ from our projections and
such estimated maintenance capital expenditures may not maintain
our production. Further, because estimated maintenance
capital expenditures are not intended to target specific levels of
reserves, if we do not acquire new proved or unproved reserves, our
total reserves will decrease over time and we would be unable to
sustain production at current levels, which could adversely affect
our ability to pay a distribution at the current level or at
all.(4) Represents total capital expenditures for the development
of oil and natural gas properties as presented on an accrual basis.
For 2016, we intend to fund our total oil and natural gas
development program from net cash provided by operating
activities.
CONTACT: Legacy Reserves LP
Dan Westcott
Executive Vice President and Chief Financial Officer
432-689-5200
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