EXHIBIT 99.1
Legacy Reserves LP Announces First Quarter 2009 Results
MIDLAND, Texas, May 6, 2009 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced first 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 May 8, 2009 within Legacy's Quarterly Report on Form 10-Q.
A summary of selected financial information follows. For complete financial statements, please see accompanying tables.
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Three Months Ended
-----------------------------
March 31, Dec. 31, March 31,
-----------------------------
2009 2008 2008
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(dollars in millions)
Production (Boe/d) 8,322 8,553 6,813
Revenue $23.1 $34.4 $48.8
Expenses $34.7 $124.6 $24.8
Operating income (loss) ($11.6) ($90.2) $24.0
Unrealized gain (loss) on commodity
derivatives $0.5 $230.4 ($34.0)
Net income (loss) $3.5 $127.1 ($21.1)
Adjusted EBITDA (*) $24.8 $17.7 $27.1
Distributable Cash Flow (*) $14.9 $0.3 $22.3
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* Non-GAAP financial measure, see Adjusted EBITDA table at the end of
this press release
Highlights of the first quarter of 2009 compared to the fourth quarter of 2008:
* Production decreased 3% to 8,322 Boe per day from 8,553 Boe
per day as a result of the reduction in development capital
expenditures to $4.8 million from $14.5 million in the prior
quarter along with downtime related to third party gas plant
maintenance in the Texas Panhandle.
* Combined realized prices were $30.79 per Boe, down 30% from
$43.73 per Boe in the fourth quarter. Oil prices were $35.79
per barrel compared to $54.53 per barrel, while natural gas
prices declined to $3.62 per Mcf from $4.77 per Mcf. Oil price
differentials to WTI widened to $7.42 per barrel from $4.22 per
barrel in the fourth quarter due to high oil storage levels at
Cushing, Oklahoma and low refinery utilization related to the
economic slowdown.
* Oil, NGL and natural gas sales were $23.1 million, a 33% decline
from $34.4 million due to the decline in combined prices and
decline in production rate.
* Commodity derivative cash settlements were $19.0 million compared
to $1.4 million due to the commodity price decline, higher hedged
commodity prices of $56.13 per Boe compared to $45.54 per Boe and
a higher percentage of hedged production at 71% compared to 64%
in the fourth quarter.
* Production expenses decreased to $10.5 million, or $14.07 per Boe,
from $12.2 million, or $15.49 per Boe.
* Adjusted EBITDA increased 40% to $24.8 million from $17.7 million
primarily due to the impact of our commodity derivatives compared
to the fourth quarter when we had $7.1 million of oil hedge
settlement lag effect.
* Distributable cash flow increased to $14.9 million from $0.3
million as a result of our $19.0 million of commodity derivative
settlements and reduced development capital expenditures.
Comparisons of the first quarter of 2009 results to the first quarter of 2008 follow:
* Production increased 22% to 8,322 Boe per day from 6,813 Boe per
day as a result of approximately $218 million of 2008
acquisitions and $32.8 million of development capital
expenditures in 2008.
* Combined realized prices were $30.79 per Boe down 61% from
$78.69 per Boe. Oil prices were $35.79 per barrel compared to
$95.12 per barrel, while natural gas prices declined to $3.62 per
Mcf from $8.73 per Mcf.
* Oil, NGL and natural gas sales were $23.1 million, a 53% decline
from $48.8 million due to lower commodity prices in the period,
partially offset by higher production volumes.
* Commodity derivative cash settlements were $19.0 million compared
to a $6.8 million loss due to the decline in commodity prices year
over year.
* Production expenses were $10.5 million, or $14.07 per Boe,
compared to $9.0 million, or $14.51 per Boe, due to the acquisition
of properties and growth in well count.
* Adjusted EBITDA decreased 8% to $24.8 million from $27.1 million
due primarily to the decline in oil and natural gas sales,
partially offset by higher commodity derivatives settlements.
* Development capital expenditures were $4.8 million; increased
from $3.0 million.
* Distributable cash flow decreased 33% to $14.9 million from
$22.3 million as a consequence of lower adjusted EBITDA, higher
cash interest expense and higher development capital expenditures.
Cary Brown, Chairman and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, said, "We delivered strong first quarter production against the headwind of lower oil and natural gas prices. I am pleased with the continued cost containment response of our operating team which was primarily responsible for a decrease of production costs to $14.07 per Boe in the first quarter of 2009 from $15.49 per Boe in the fourth quarter of 2008. Given current oil, NGL and natural gas prices, we expect production and capital costs to continue to decline in 2009."
Distribution Policy
Mr. Brown continued, "Our Board of Directors has decided to maintain our current quarterly distribution level of $0.52 for the first quarter. Our distributable cash flow was $0.48 per unit. We hedged 71% of our production in the first quarter, and the settlement of our commodity hedges contributed $19.0 million to our adjusted EBITDA. We expect our cash flow from production and our hedges to support our 2009 distribution and our borrowing base. In an effort to improve distribution coverage and liquidity for the remainder of the year, the board approved a reduction in our capital budget to $10.7 million from $20 million. With respect to any future distributions, we continue to review our distribution policy to maintain liquidity given the volatile commodity price and capital markets environment."
Credit Facility Extension
Steven Pruett, President and Chief Financial Officer, commented on the extension of Legacy's Credit Agreement, "On March 27th, we announced the extension credit facility and the reduction in our borrowing base to $340 million from $410 million in the fall. The extension in maturity to April 1, 2012 from the original maturity of March 16, 2010, resulted in $4.3 million of upfront fees that were paid in the first quarter but will be expensed over the life of the facility. The LIBOR interest rate margin ranges from 2.25% to 3.0% which is 0.75% higher than the previous Credit Agreement. The commitment fee on unused capacity has been increased to 0.5% from 0.375% previously. We have $300 million of debt drawn on our credit facility as of today, leaving $40 million of availability."
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 Reserves LP at a cash purchase price of $14.00 per unit, subject to adjustment for any distributions paid to the Partnership's limited partners. The Conflicts Committee of the Board of Directors has not made any decision with respect to the proposal. There can be no assurance that any definitive offer will be made, an agreement will be executed, or that any transaction will be approved or consummated.
Net Income
Net income for the first quarter of 2009 was $3.5 million, which was impacted by impairment of approximately $1.2 million due to lower natural gas prices than compared to year-end 2008. We had $0.5 million of unrealized gains on commodity derivatives in the first quarter. In the fourth quarter of 2008, we reported net income of $127.1 million, which included $230.4 million of unrealized gains on commodity derivatives, losses from impairment of $76.5 million and depletion, depreciation and amortization of $30.1 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 May 6, 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 April 2009 through December 2013:
Annual Average Price
Calendar Year Volumes (Bbls) Price per Bbl Range per Bbl
------------- ---------------- --------------- ------------------
Apr-Dec 2009 1,117,920 $ 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 240,000 $ 82.00 $82.00
Average Price
Calendar Year Volumes (MMBtu) Price per MMBtu Range per MMBtu
------------- ---------------- --------------- ------------------
Apr-Dec 2009 2,379,340 $ 7.94 $6.85 - $9.29
2010 2,840,859 $ 7.87 $6.85 - $9.73
2011 2,127,316 $ 8.01 $6.85 - $8.70
2012 1,579,736 $ 8.02 $6.85 - $8.70
Additionally, we have entered into a NYMEX WTI derivative collar contracts with the following attributes:
Annual Average Average
Calendar Year Volumes (Bbl) Put ($/Bbl) Call ($/Bbl)
------------- ---------------- --------------- ------------------
Apr-Dec 2009 56,800 $ 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:
Waha Basis Swaps Annual Basis Differential
Calendar Year Volumes (MMBtu) per MMBtu
---------------------- --------------------- ----------------------
Apr-Dec 2009 990,000 $ (0.68)
2010 1,200,000 $ (0.57)
In December 2008, we entered into additional basis swaps for our Texas Panhandle and Oklahoma natural gas whose price tracks ANR-Oklahoma more closely than Henry Hub. The table below summarizes our NYMEX - ANR-Oklahoma basis swaps:
ANR-OK Basis Swaps Annual Basis Differential
Calendar Year Volumes (MMBtu) per MMBtu
---------------------- --------------------- ----------------------
Apr-Dec 2009 360,000 $ (1.09)
2010 480,000 $ (0.87)
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
--------------------- -------------- --------------- ---------
Apr-Dec 2009 1,699,110 $ 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 los ses 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 March 31, 2009 Form 10-Q, which will be filed on or about May 8, 2009.
Conference Call
As announced on April 28, 2009, Legacy Reserves LP will host a teleconference and webcast to discuss Legacy's results on Thursday, May 7, 2009 at 10:00 a.m. (Central Time). Those wishing to participate in the conference call should dial 888-219-1217. A replay of the call will be available through 5:00 pm Central Time Monday, May 11, 2009, by dialing 719-457-0820 or 888-203-1112 and entering code 1126450. 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. 00 1-33249). 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
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March 31, Dec. 31, March 31,
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2009 2008 2008
--------- --------- ---------
(In thousands, except per unit data)
Revenues:
Oil sales $ 16,465 $ 25,573 $ 36,049
Natural gas liquids sales (NGL) 2,069 2,548 3,502
Natural gas sales 4,525 6,296 9,236
--------- --------- ---------
Total revenues 23,059 34,417 48,787
--------- --------- ---------
Expenses:
Oil and natural gas production 12,002 13,177 9,528
Production and other taxes 1,353 2,058 2,469
General and administrative 3,368 2,524 3,018
Depletion, depreciation,
amortization and accretion 16,621 30,102 9,617
Impairment of long-lived assets 1,156 76,495 104
Loss on disposal of assets 208 211 48
--------- --------- ---------
Total expenses 34,708 124,567 24,784
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Operating income (loss) (11,649) (90,150) 24,003
Other income (expense):
Interest income 1 12 55
Interest expense (4,259) (13,989) (4,178)
Equity in income (loss) of
partnerships (2) (26) 42
Realized and unrealized gain
(loss) on oil, NGL and natural gas
swaps and oil collar 19,505 231,816 (40,793)
Other 4 144 (16)
--------- --------- ---------
Income (loss) before income taxes 3,600 127,807 (20,887)
Income taxes (111) 581 (210)
--------- --------- ---------
Income (loss) from continuing
operations 3,489 128,388 (21,097)
Gain (loss) on sale of discontinued
operation -- (1,250) --
Net income (loss) $ 3,489 $127,138 $(21,097)
========= ========= =========
Income (loss) from continuing
operations per unit - basic and
diluted $ 0.11 $ 4.13 $ (0.71)
========= ========= =========
Gain (loss) on discontinued
operation per unit - basic and
diluted $ -- $ (0.04) $ --
========= ========= =========
Net income (loss) per unit -
basic and diluted $ 0.11 $ 4.09 $ (0.71)
========= ========= =========
Weighted average number of units
used in computing net income per
unit
basic 31,053 31,049 29,674
========= ========= =========
diluted 31,067 31,059 29,674
========= ========= =========
LEGACY RESERVES LP
CONSOLIDATED BALANCE SHEET (UNAUDITED)
(dollars in thousands)
March 31,
2009
---------
ASSETS
Current assets:
Cash and cash equivalents $ 3,034
Accounts receivable, net:
Oil and natural gas 10,738
Joint interest owners 7,669
Other 41
Fair value of derivatives 56,279
Prepaid expenses and other current assets 4,523
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Total current assets 82,284
---------
Oil and natural gas properties, at cost:
Proved oil and natural gas properties, using the
successful efforts method of accounting 826,323
Unproved properties 78
Accumulated depletion, depreciation and amortization (225,029)
---------
601,372
---------
Other property and equipment, net of accumulated
depreciaton and amortization of $928 1,742
Operating rights, net of amortization of $1,566 5,451
Fair value of derivatives 79,151
Other assets, net of amortization of $1,394 5,795
Investment in equity method investee 14
---------
Total assets $ 775,809
=========
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 1,671
Accrued oil and natural gas liabilities 11,147
Fair value of derivatives 5,006
Asset retirement obligation 29,210
Other 2,622
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Total current liabilities 49,656
---------
Long-term debt 300,000
Asset retirement obligation 51,210
Fair value of derivatives 6,819
Other long-term liabilities 90
---------
Total liabilities 407,775
---------
Commitments and contingencies
Unitholders' equity:
Limited partners' equity - 31,069,339 units issued and
outstanding at March 31, 2008 367,917
General partner's equity 117
---------
Total unitholders' equity 368,034
---------
Total liabilities and unitholders' equity $ 775,809
=========
Selected Financial and Operating Data
Three Months Ended
March 31, Dec. 31, March 31,
---------- ---------- ----------
2009 2008 2008
---------- ---------- ----------
(In thousands, except per unit data)
Revenues:
Oil sales $ 16,465 $ 25,573 $ 36,049
Natural gas liquid sales 2,069 2,548 3,502
Natural gas sales 4,525 6,296 9,236
---------- ---------- ----------
Total revenue $ 23,059 $ 34,417 $ 48,787
========== ========== ==========
Expenses:
Oil and natural gas production $ 10,537 $ 12,189 $ 8,996
Ad valorem taxes $ 1,465 $ 988 $ 532
---------- ---------- ----------
Total oil and natural gas
production including ad valorem
taxes $ 12,002 $ 13,177 $ 9,528
Production and other taxes $ 1,353 $ 2,058 $ 2,469
General and administrative $ 3,368 $ 2,524 $ 3,018
Depletion, depreciation,
amortization and accretion $ 16,621 $ 30,102 $ 9,617
Realized swap settlements:
Realized gain (loss) on oil swaps $ 14,912 $ (1,549) $ (6,578)
Realized gain (loss) on natural gas
liquid swaps $ 470 $ 67 $ (721)
Realized gain on natural gas swaps $ 3,597 $ 2,907 $ 532
Production:
Oil - barrels 460 469 379
Natural gas liquids - gallons 3,388 4,134 2,721
Natural gas - Mcf 1,249 1,320 1,058
Total (MBoe) 749 787 620
Average daily production (Boe/d) 8,322 8,553 6,813
Average sales price per unit:
Oil price per barrel $ 35.79 $ 54.53 $ 95.12
Natural gas liquid price per gallon $ 0.61 $ 0.62 $ 1.29
Natural gas price per Mcf $ 3.62 $ 4.77 $ 8.73
Combined (per Boe) $ 30.79 $ 43.73 $ 78.69
Average sales price per unit
(including realized derivative
settlements):
Oil price per barrel $ 68.21 $ 51.22 $ 77.76
Natural gas liquid price per gallon $ 0.75 $ 0.63 $ 1.02
Natural gas price per Mcf $ 6.50 $ 6.97 $ 9.23
Combined (per Boe) $ 56.13 $ 45.54 $ 67.77
NYMEX oil index prices per barrel:
Beginning of Period $ 44.60 $ 100.64 $ 95.98
End of Period $ 49.66 $ 44.60 $ 101.58
NYMEX gas index prices per Mcf:
Beginning of Period $ 5.62 $ 7.72 $ 7.48
End of Period $ 3.78 $ 5.62 $ 10.10
Average unit costs per Boe:
Oil and natural gas production $ 14.07 $ 15.49 $ 14.51
Ad valorem taxes $ 1.96 $ 1.26 $ 0.86
Production and other taxes $ 1.81 $ 2.61 $ 3.98
General and administrative $ 4.50 $ 3.21 $ 4.87
Depletion, depreciation,
amortization and accretion $ 22.19 $ 38.25 $ 15.51
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:
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Three Months Ended
-------------------------------
March 31, Dec. 31, March 31,
--------- --------- ---------
2009 2008 2008
--------- --------- ---------
(dollars in thousands)
Net income (loss) $ 3,489 $ 127,138 $ (21,097)
Plus:
Interest expense 4,259 13,989 4,178
Income taxes 111 (581) 210
Depletion, depreciation,
amortization and accretion 16,621 30,102 9,617
Impairment of long-lived assets 1,156 76,495 104
(Gain) loss on sale of assets (60) 1,223 --
Equity in (income) loss of
partnership 2 26 (42)
Compensation expense on LTIP and
restricted units (281) (282) 138
Unrealized (gain) loss on oil and
natural gas derivatives (526) (230,390) 34,026
--------- --------- ---------
Adjusted EBITDA $ 24,771 $ 17,720 $ 27,134
Less:
Cash interest expense 4,955 2,859 1,837
LTIP settlements 176 52 --
Development capital expenditures 4,769 14,469 2,987
--------- --------- ---------
Distributable Cash Flow $ 14,871 $ 340 $ 22,310
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CONTACT: Legacy Reserves LP
Steven H. Pruett, President and Chief Financial Officer
432-689-5200
