Legacy Reserves LP Announces Second Quarter 2009 Results
- Press Release
- Source: Legacy Reserves LP
- On 5:59 pm EDT, Wednesday August 5, 2009
MIDLAND, Texas, Aug. 5, 2009 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY - News) today announced second quarter results for 2009. This unaudited financial information is preliminary and is subject to adjustments in connection with the final unaudited financial statements to be released on or about August 7, 2009 within Legacy's Quarterly Report on Form 10-Q.
Related Quotes
| Symbol | Price | Change |
|---|---|---|
| LGCY | 17.53 | +0.19 |
A summary of selected financial information follows. For complete financial statements, please see accompanying tables.
---------------------------------------------------------------------
Three Months Ended Six Months Ended
--------------------- ---------------------
June 30, March 31, June 30, June 30,
-------------------------------------------
2009 2009 2009 2008
---------------------------------------------------------------------
(dollars in millions)
Production (Boe/d) 8,154 8,322 8,238 7,088
Revenue $31.9 $23.1 $54.9 $115.4
Expenses $31.3 $34.7 $66.0 $56.6
Operating income (loss) $0.6 ($11.6) ($11.1) $58.8
Unrealized gain (loss) on
commodity swaps ($75.8) $0.5 ($75.3) ($235.4)
Net income (loss) ($57.0) $3.5 ($53.5) ($196.9)
Adjusted EBITDA (*) $32.0 $24.8 $56.8 $58.6
Distributable Cash Flow
(*) $24.7 $14.9 $39.6 $47.5
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* Non-GAAP financial measure, see Adjusted EBITDA table at the end of
this press release
Highlights of the second quarter of 2009 compared to the first quarter of 2009:
-- Production decreased 2% to 8,154 Boe per day from 8,322 Boe per
day as a result of the reduction in development capital
expenditures in the first half of 2009 compared to the second half
of 2008 along with downtime related to third party gas plant
maintenance in the Texas Panhandle.
-- Combined realized prices were $42.93 per Boe, up 39% from $30.79
per Boe in the first quarter excluding the impact of commodity
derivatives. Oil prices were $55.79 per barrel compared to $35.79
per barrel, while natural gas prices increased marginally to $3.79
per Mcf from $3.62 per Mcf.
-- Oil, NGL and natural gas sales were $31.9 million, a 38% increase
from $23.1 million due to the increase in commodity prices which
more than offset slightly lower production volumes.
-- Commodity derivative cash settlements decreased to $16.7 million
compared to $19.0 million due to commodity price increases.
Included in the $16.7 million of settlements is a $3.0 million
benefit due to settlement timing in an increasing price
environment, compared to a $1.3 million detriment in the first
quarter as prices fell from the prior quarter.
-- Production expenses increased modestly to $10.7 million, or $14.38
per Boe, from $10.5 million, or $14.07 per Boe.
-- Adjusted EBITDA increased 29% to $32.0 million from $24.8 million
due to the impact of increased commodity prices compared to the
first quarter.
-- Development capital expenditures were $2.6 million reduced from
$4.8 million in the prior quarter.
-- Distributable cash flow increased to $24.7 million from $14.9
million as a result of our higher EBITDA and reduced development
capital expenditures.
Comparisons of the six months ended June 30, 2009 results to the six months ended June 30, 2008 follow:
-- Production increased 16% to 8,238 Boe per day from 7,088 Boe per
day as a result of our acquisitions and development capital
expenditures in 2008.
-- Combined realized prices were $36.83 per Boe, down 59% from $89.45
per Boe. Oil prices were $45.58 per barrel compared to $109.02
per barrel, while natural gas prices declined to $3.71 per Mcf
from $9.85 per Mcf.
-- Oil, NGL and natural gas sales were $54.9 million, a 52% decline
from $115.4 million due to lower commodity prices in the period,
partially offset by higher production volumes.
-- Commodity derivative cash settlements received were $35.6 million
compared to a $21.9 million loss due to the decline in commodity
prices year over year.
-- Production expenses were $21.2 million, or $14.22 per Boe,
compared to $21.3 million, or $16.48 per Boe, due to the lower
commodity price environment offset by the acquisition of
properties and growth in well count.
-- Adjusted EBITDA decreased 3% to $56.8 million from $58.6 million
due primarily to the decline in oil and natural gas sales
revenues, offset by higher commodity derivatives settlements.
-- Development capital expenditures remain unchanged year over year
at $7.4 million.
-- Distributable cash flow decreased 17% to $39.6 million from $47.5
million as a consequence of lower adjusted EBITDA and higher cash
interest expense.
Cary Brown, Chairman and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, said, "We had strong distribution coverage in the second quarter in excess of 1.5 times our $0.52 quarterly distribution. Our $8.5 million of excess distributable cash flow coupled with our improved liquidity outlook and our favorable long-term commodity hedges have bolstered our confidence in continuing to support a $0.52 quarterly distribution. We are pleased to remain public and to continue to pay a cash distribution to our investors."
Take Private Offer
On April 3, 2009, Legacy's Board of Directors announced the receipt of a proposal from Apollo Management VII, LP to acquire all of the outstanding units of Legacy at a cash purchase price of $14.00 per unit, subject to adjustment for any distributions paid to Legacy's limited partners. On June 24, 2009, after careful review of the Proposal Letter and subsequent negotiations relating to the Proposal Letter, Legacy's Conflicts Committee determined that it was in the best interest of the unitholders of Legacy to terminate discussions with Apollo Management.
Net Income/Loss
Legacy incurred a net loss for the second quarter of 2009 of $57.0 million, which was impacted by unrealized losses on oil and natural gas swaps of approximately $75.8 million due to increases in oil and natural gas prices from the end of the first quarter as well as depletion, depreciation and amortization of $13.5 million. In the first quarter of 2009, we reported net income of $3.5 million, which included $0.5 million of unrealized gains on commodity derivatives and depletion, depreciation and amortization of $16.6 million.
Commodity Derivatives
We have entered into the following fixed price swaps for oil and natural gas to help mitigate the risk of changing commodity prices. As of August 5, 2009, we had entered into swap agreements to receive average NYMEX West Texas Intermediate oil and Henry Hub, Waha and ANR-Oklahoma natural gas prices as summarized below starting with July 2009 through December 2013:
Annual Average Price
Calendar Year Volumes (Bbls) Price per Bbl Range per Bbl
--------------------- --------------- -------------- ----------------
July - December 2009 745,626 $ 82.82 $61.05 - $140.00
2010 1,397,973 $ 82.37 $60.15 - $140.00
2011 1,155,712 $ 88.07 $67.33 - $140.00
2012 969,812 $ 81.28 $67.72 - $109.20
2013 490,025 $ 81.31 $80.10 - $82.00
Average Price
Calendar Year Volumes (MMBtu) Price per MMBtu Range per MMBtu
--------------------- --------------- --------------- ---------------
July - December 2009 1,828,231 $ 7.38 $3.40 - $9.29
2010 3,740,859 $ 7.26 $5.33 - $9.73
2011 2,892,316 $ 7.57 $6.13 - $8.70
2012 1,945,736 $ 7.79 $6.80 - $8.70
2013 730,000 $ 6.89 $6.89
Additionally, we have entered into NYMEX WTI derivative collar contracts with the following attributes:
Annual Average Average
Calendar Year Volumes (Bbl) Put ($/Bbl) Call ($/Bbl)
----------------------- -------------- ------------- ----------------
July - December 2009 38,000 $ 120.00 $ 156.30
2010 71,800 $ 120.00 $ 156.30
2011 68,300 $ 120.00 $ 156.30
2012 65,100 $ 120.00 $ 156.30
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.
We have entered into natural gas basis swaps to receive floating NYMEX prices less a fixed basis differential and pay prices based on the floating Waha index, a natural gas hub in West Texas. The prices that we receive for our Permian Basin natural gas sales follow Waha more closely than the NYMEX Henry Hub natural gas index. The basis swaps thereby provide a better correlation between our natural gas sales and the derivative settlement payments on our natural gas swaps. The following table summarizes, for the periods indicated, our NYMEX-Waha basis swaps currently in place for production months through December 31, 2010:
Average Basis
Waha Basis Swaps Annual Basis Differential
Calendar Year Volumes (MMBtu) Differential per MMBtu
----------------------- -------------- ------------- ----------------
July - December 2009 660,000 $ (0.68) $ (0.68)
2010 1,200,000 $ (0.57) $ (0.57)
In 2007, we entered into NGL swaps to hedge the impact of volatility in the spot prices of NGLs. The commodity prices covered by these swaps are the spot prices for ethane, propane, iso-butane, normal butane and natural gasoline reported on the Mont Belvieu, Non-Tet OPIS exchange. The following table summarizes, for the periods indicated, our Mont Belvieu, Non-Tet OPIS NGL swaps currently in place for production months through December 2009.
Annual Average Price
Calendar Year Volumes (Gal) Price per Gal per Gal
----------------------- -------------- ------------- ----------------
July - December 2009 1,132,740 $ 1.15 $1.15
Legacy enters into derivative transactions with unaffiliated third parties with respect to oil, NGL and natural gas prices to achieve more predictable cash flows and to reduce its exposure to short-term fluctuations in oil, NGL and natural gas prices. These derivative instruments are accounted for in accordance with SFAS No. 133 - Accounting for Derivative Instruments and Hedging Activities. These instruments are intended to mitigate a portion of Legacy's price risk and may be considered hedges for economic purposes but Legacy has chosen not to designate them as cash flow hedges for accounting purposes. Therefore, all derivative instruments are recorded on the balance sheet at fair value which requires us to mark our future derivatives positions to market each quarter resulting in unrealized gains or losses, which impact reported net income. Unrealized gains or losses represent current period mark-to-market adjustments for commodity derivatives which will be settled in future periods. Unrealized gains or losses result in a non-cash impact on earnings and do not affect our ability to make our expected cash distributions. The majority of our derivative instruments now in place are in the form of swaps of floating prices for fixed prices paid by the counterparty.
Quarterly Report on Form 10-Q
The condensed consolidated financial statements and related footnotes will be available in our June 30, 2009 Form 10-Q, which will be filed on or about August 7, 2009.
Conference Call
As announced on July 29, 2009, Legacy Reserves LP will host a teleconference and webcast to discuss Legacy's results on Thursday, August 6, 2009 at 2:00 p.m. (Central Time). Those wishing to participate in the conference call should dial 888-569-5033. A replay of the call will be available through midnight Monday, August 10, 2009, by dialing 719-457-0820 or 888-203-1112 and entering code 5986426. Those wishing to listen to the live or archived webcast via the internet should go to the Investor Relations tab of Legacy's website (www.LegacyLP.com).
About Legacy Reserves LP
We are an independent oil and natural gas limited partnership headquartered in Midland, Texas, focused on the acquisition and development of oil and natural gas properties primarily located in the Permian Basin and Mid-continent regions of the United States. Additional information is available at www.LegacyLP.com.
The Legacy Reserves logo is available at http://www.globenewswire.com/newsroom/prs/?pkgid=3201
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 the 2008 Annual Report on Form 10-K filed March 6, 2009 (File No. 001-33249). 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 Six Months Ended
--------------------- ---------------------
June 30, March 31, June 30, June 30,
---------- ---------- ---------- ----------
2009 2009 2009 2008
---------- ---------- ---------- ----------
(In thousands, except per unit data)
Revenues:
Oil sales $ 24,604 $ 16,465 $ 41,069 $ 84,488
Natural gas liquids
sales (NGL) 2,478 2,069 4,547 8,283
Natural gas sales 4,773 4,525 9,298 22,625
---------- ---------- ---------- ----------
Total revenues 31,855 23,059 54,914 115,396
---------- ---------- ---------- ----------
Expenses:
Oil and natural gas
production 11,468 12,002 23,471 23,042
Production and other
taxes 1,887 1,353 3,240 6,558
General and
administrative 3,900 3,368 7,268 6,714
Depletion, depreciation,
amortization and
accretion 13,549 16,621 30,170 20,140
Impairment of long-lived
assets 452 1,156 1,608 108
Loss on disposal of
assets 31 208 239 75
---------- ---------- ---------- ----------
Total expenses 31,287 34,708 65,996 56,637
---------- ---------- ---------- ----------
Operating income
(loss) 568 (11,649) (11,082) 58,759
Other income (expense):
Interest income 5 1 6 71
Interest expense 1,761 (4,259) (2,498) (2,966)
Equity in income (loss)
of partnerships -- (2) (3) 87
Realized and unrealized
gain (loss) on oil, NGL
and natural gas swaps
and oil collar (59,172) 19,505 (39,666) (257,260)
Other 6 4 10 (19)
---------- ---------- ---------- ----------
Income (loss) before
income taxes (56,832) 3,600 (53,233) (201,328)
Income taxes (160) (111) (270) (507)
---------- ---------- ---------- ----------
Income (loss) from
continuing operations (56,992) 3,489 (53,503) (201,835)
Gain on sale of
discontinued operation -- -- -- 4,954
---------- ---------- ---------- ----------
Net income (loss) $ (56,992) $ 3,489 $ (53,503) $(196,881)
========== ========== ========== ==========
Income (loss) from
continuing operations
per unit -
basic and diluted $ (1.83) $ 0.11 $ (1.72) $ (6.70)
========== ========== ========== ==========
Gain on discontinued
operation per unit -
basic and diluted $ -- $ -- $ -- $ 0.16
========== ========== ========== ==========
Net income (loss) per
unit -
basic and diluted $ (1.83) $ 0.11 $ (1.72) $ (6.53)
========== ========== ========== ==========
Weighted average
number of units used
in computing net
income per unit
basic 31,069 31,053 31,061 30,141
========== ========== ========== ==========
diluted 31,069 31,067 31,061 30,141
========== ========== ========== ==========
LEGACY RESERVES LP
CONSOLIDATED BALANCE SHEET (UNAUDITED)
(dollars in thousands)
June 30,
2009
----------
ASSETS
Current assets:
Cash and cash equivalents $ 7,400
Accounts receivable, net:
Oil and natural gas 14,520
Joint interest owners 4,405
Other 57
Fair value of derivatives 27,698
Prepaid expenses and other current assets 3,434
----------
Total current assets 57,514
----------
Oil and natural gas properties, at cost:
Proved oil and natural gas properties, using the
successful efforts method of accounting 828,841
Unproved properties 78
Accumulated depletion, depreciation and amortization (238,035)
----------
590,884
----------
Other property and equipment, net of accumulated
depreciation and amortization of $1,098 1,647
Operating rights, net of amortization of $1,704 5,313
Fair value of derivatives 39,319
Other assets, net of amortization of $1,849 5,379
Investment in equity method investee 14
----------
Total assets $ 700,070
==========
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 2,159
Accrued oil and natural gas liabilities 12,087
Fair value of derivatives 7,037
Asset retirement obligation 4,162
Other 2,891
----------
Total current liabilities 28,336
----------
Long-term debt 295,000
Asset retirement obligation 76,300
Fair value of derivatives 5,422
Other long-term liabilities 117
----------
Total liabilities 405,175
----------
Commitments and contingencies
Unitholders' equity:
Limited partners' equity - 31,069,339 units issued and
outstanding at June 30, 2009 294,822
General partner's equity 73
----------
Total unitholders' equity 294,895
----------
Total liabilities and unitholders' equity $ 700,070
==========
Selected Financial and Operating Data
Three Months Ended Six Months Ended
--------------------- ---------------------
June 30, March 31, June 30, June 30,
---------- ---------- ---------- ----------
2009 2009 2009 2008
---------- ---------- ---------- ----------
(In thousands, except per unit data)
Revenues:
Oil sales $ 24,604 $ 16,465 $ 41,069 $ 84,488
Natural gas liquid sales 2,478 2,069 4,547 8,283
Natural gas sales 4,773 4,525 9,298 22,625
---------- ---------- ---------- ----------
Total revenue $ 31,855 $ 23,059 $ 54,914 $ 115,396
========== ========== ========== ==========
Expenses:
Oil and natural gas
production $ 10,671 $ 10,537 $ 21,209 $ 21,253
Ad valorem taxes $ 797 $ 1,465 $ 2,262 $ 1,789
---------- ---------- ---------- ----------
Total oil and natural
gas production
including ad valorem
taxes $ 11,468 $ 12,002 $ 23,471 $ 23,042
Production and other
taxes $ 1,887 $ 1,353 $ 3,240 $ 6,558
General and
administrative $ 3,900 $ 3,368 $ 7,268 $ 6,714
Depletion, depreciation,
amortization and
accretion $ 13,549 $ 16,621 $ 30,170 $ 20,140
Realized swap settlements:
Realized gain (loss) on
oil swaps $ 12,683 $ 14,912 $ 27,595 $ (19,173)
Realized gain (loss) on
natural gas liquid
swaps $ 202 $ 470 $ 672 $ (1,733)
Realized gain on natural
gas swaps $ 3,770 $ 3,597 $ 7,367 $ (1,002)
Production:
Oil - barrels 441 460 901 775
Natural gas liquids -
gallons 3,843 3,388 7,232 5,543
Natural gas - Mcf 1,259 1,249 2,508 2,296
Total (MBoe) 742 749 1,491 1,290
Average daily production
(Boe/d) 8,154 8,322 8,238 7,088
Average sales price per
unit (excluding swaps):
Oil price per barrel $ 55.79 $ 35.79 $ 45.58 $ 109.02
Natural gas liquid price
per gallon $ 0.64 $ 0.61 $ 0.63 $ 1.49
Natural gas price per
Mc $ 3.79 $ 3.62 $ 3.71 $ 9.85
Combined (per Boe) $ 42.93 $ 30.79 $ 36.83 $ 89.45
Average sales price per
unit (including realized
swap settlements):
Oil price per barrel $ 84.55 $ 68.21 $ 76.21 $ 84.28
Natural gas liquid price
per gallon $ 0.70 $ 0.75 $ 0.72 $ 1.18
Natural gas price per
Mcf $ 6.79 $ 6.50 $ 6.64 $ 9.42
Combined (per Boe) $ 65.38 $ 56.13 $ 60.73 $ 72.47
NYMEX oil index prices per
barrel:
Beginning of Period $ 49.66 $ 44.60 $ 44.60 $ 95.98
End of Period $ 69.89 $ 49.66 $ 69.89 $ 140.00
NYMEX gas index prices per
Mcf:
Beginning of Period $ 3.78 $ 5.62 $ 5.62 $ 7.48
End of Period $ 3.84 $ 3.78 $ 3.84 $ 13.35
Average unit costs per
Boe:
Oil and natural gas
production $ 14.38 $ 14.07 $ 14.22 $ 16.48
Ad valorem taxes $ 1.07 $ 1.96 $ 1.52 $ 1.39
Production and other
taxes $ 2.54 $ 1.81 $ 2.17 $ 5.08
General and
administrative $ 5.26 $ 4.50 $ 4.87 $ 5.20
Depletion, depreciation,
amortization and
accretion $ 18.26 $ 22.19 $ 20.23 $ 15.61
Non-GAAP Financial Measures
This press release, the financial tables and other supplemental information, including the reconciliation of "Adjusted EBITDA" and "Distributable Cash Flow", both of which are non-generally accepted accounting principles ("non-GAAP") measures to their nearest comparable generally accepted accounting principles ("GAAP") measure, may be used periodically by management when discussing our financial results with investors and analysts. All such information is also available on our website under the Investor Relations link.
"Adjusted EBITDA" and "Distributable Cash Flow" should not be considered as alternatives to GAAP measures, such as net income, operating income or any other GAAP measure of liquidity or financial performance.
Adjusted EBITDA is defined in our revolving credit facility 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;
-- Unit-based compensation expense arising from liability and equity-
based awards;
-- Equity in (income) loss of partnerships; and
-- Unrealized (gain) loss on oil and natural gas derivatives.
Distributable Cash Flow is defined as Adjusted EBITDA less:
-- Cash interest expense; -- Cash income taxes; -- Cash settlements of unit options; and -- Development capital expenditures.
Adjusted EBITDA and Distributable Cash Flow are presented as management believes they provide additional information and metrics relative to the performance of our business, such as the cash distributions we expect to pay to our unitholders, as well as our ability to meet our debt covenant compliance tests. Management believes that these financial measures indicate to investors whether or not cash flow is being generated at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA and Distributable Cash Flow may not be comparable to a similarly titled measure of other publicly traded limited partnerships or limited liability companies because all companies may not calculate Adjusted EBITDA in the same manner.
The following table presents a reconciliation of our consolidated net income (loss) to Adjusted EBITDA and Distributable Cash Flow:
---------------------------------------------------------------------
Three Months Ended Six Months Ended
--------------------- ---------------------
June 30, March 31, June 30, June 30,
---------- ---------- ---------- ----------
2009 2009 2009 2008
---------- ---------- ---------- ----------
(dollars in thousands)
Net income (loss) $ (56,992) $ 3,489 $ (53,503) $(196,881)
Plus:
Interest expense
(income) (1,761) 4,259 2,498 2,966
Income taxes 160 111 270 507
Depletion,
depreciation,
amortization and
accretion 13,549 16,621 30,170 20,140
Impairment of long-
lived assets 452 1,156 1,608 108
(Gain) loss on sale of
assets -- (60) (60) (4,942)
Equity in (income)
loss of partnership -- 2 3 (87)
Compensation expense
on LTIP and
restricted units 817 (281) 536 1,477
Unrealized (gain) loss
on oil and natural
gas swaps 75,827 (526) 75,300 235,352
---------- ---------- ---------- ----------
Adjusted EBITDA $ 32,052 $ 24,771 $ 56,822 $ 58,640
Less:
Cash interest expense 4,655 4,955 9,610 3,786
LTIP settlements 59 176 235 34
Development capital
expenditures 2,647 4,769 7,416 7,364
---------- ---------- ---------- ----------
Distributable Cash Flow $ 24,691 $ 14,871 $ 39,561 $ 47,456
---------------------------------------------------------------------
Contact:
Legacy Reserves LP
Steven H. Pruett, President and Chief Financial Officer
432-689-5200
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