Legacy Reserves LP Announces Third Quarter 2009 Results
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MIDLAND, Texas, Nov. 4, 2009 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq: LGCY) today announced third 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 November 6, 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.
(dollars in millions)
Three Months Ended Nine Months Ended
-------------------- --------------------
Sept. 30, June 30, Sept. 30, Sept. 30,
2009 2009 2009 2008
--------- --------- --------- ---------
Production
(Boe/d) 8,185 8,154 8,220 7,255
Revenue $37.9 $31.9 $92.8 $181.0
Expenses $34.5 $31.3 $100.5 $92.4
Operating income
(loss) $3.4 $0.6 ($7.7) $88.6
Unrealized gain (loss)
on commodity swaps ($5.7) ($75.8) ($81.0) ($13.2)
Net income (loss) ($0.9) ($57.0) ($54.4) $31.1
Adjusted EBITDA (*) $30.8 $32.1 $87.6 $82.0
Distributable Cash
Flow (*) $23.3 $24.7 $62.8 $57.0
* Non-GAAP financial measure, see Adjusted EBITDA and Distributable
Cash Flow table at the end of this press release
Highlights of the third quarter of 2009 compared to the second quarter of 2009:
-- Production increased 8,185 Boe per day from 8,154 Boe per day
despite only $3.0 million and $2.6 million of development capital
expenditures in the third and second quarters of 2009,
respectively.
-- Combined realized prices were $50.33 per Boe, up 17% from $42.93
per Boe in the second quarter excluding the favorable impact of
commodity derivatives. Oil prices were $65.38 per barrel compared
to $55.79 per barrel, while natural gas prices increased to $4.51
per Mcf from $3.79 per Mcf.
-- Oil, NGL and natural gas sales were $37.9 million, a 19% increase
from $31.9 million due to the increase in commodity prices as well
as slightly higher production volumes.
-- Commodity derivative cash settlements decreased to $10.1 million
compared to $16.7 million due to commodity price increases.
-- Production expenses excluding ad valorem and production taxes
increased 7% to $11.5 million, or $15.22 per Boe, from
$10.7 million, or $14.38 per Boe, primarily due to higher levels
of discretionary workover activity to improve production.
-- General and administrative expenses were $4.0 million, or $5.31 per
Boe, compared to $3.9 million, or $5.26 per Boe, in the second
quarter. The third quarter included $1.5 million of non-cash
compensation expense related to Legacy's incentive plan due to
increases in unit price, compared to $0.8 million in the second
quarter of 2009. The second quarter also included $1.1 million of
costs incurred related to the Apollo Offer.
-- Adjusted EBITDA decreased 4% to $30.8 million from $32.1 million
primarily due to lower commodity hedge settlements and higher
expenses which more than offset higher revenue.
-- Distributable cash flow decreased 6% to $23.3 million from $24.7
million primarily as a result of our lower EBITDA.
Comparisons of the nine months ended September 30, 2009 results to the nine months ended September 30, 2008 follow:
-- Production increased 13% to 8,220 Boe per day from 7,255 Boe per
day as a result of our acquisitions and development capital
expenditures over the past year.
-- Combined realized prices were $41.36 per Boe, down 55% from
$91.05 per Boe. Oil prices were $52.06 per barrel compared to
$111.17 per barrel, while natural gas prices declined to $3.98
per Mcf from $10.03 per Mcf.
-- Oil, NGL and natural gas sales were $92.8 million, a 49% decline
from $181.0 million due to lower commodity prices in the period,
partially offset by higher production volumes.
-- Commodity derivative cash settlements received were $45.8 million
compared to a $41.7 million loss due to the decline in commodity
prices year over year.
-- Production expenses excluding ad valorem and production taxes were
$32.7 million, or $14.56 per Boe, compared to $36.0 million, or
$18.11 per Boe, due to the lower costs related to reduced
commodity prices partially offset by the acquisition of
properties and growth in well count.
-- Adjusted EBITDA increased 7% to $87.6 million from $82.0 million
due primarily to higher commodity derivatives settlements,
increased production volumes, and lower expenses.
-- Development capital expenditures decreased year over year to
$10.4 million from $18.3 million due to reduced drilling activity
and lower cost of services in 2009 compared to 2008.
-- Distributable cash flow increased 10% to $62.8 million from $57.0
million as a result of higher adjusted EBITDA and lower
development capital expenditures.
Cary Brown, Chairman and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, said, "We had excellent production performance in light of low development expenditures over the past two quarters. Our distributable cash flow of $0.67 per unit, which includes our recent issuance of 3.8 million units, provided 1.29 times coverage of our $0.52 third quarter distribution payable on November 13, 2009. Our equity offering improved our liquidity, with $117.7 million of current availability on our credit facility that we intend to deploy in acquisitions in the coming quarters. We were pleased to maintain our borrowing base at $340 million after our fall redetermination. We acquired $5.6 million of Permian Basin producing properties in three negotiated transactions during the third quarter, and we are encouraged by the number of properties we are seeing that are available for sale. Our property evaluation team has never been busier."
Net Income/Loss
Legacy incurred a net loss for the third quarter of 2009 of $0.9 million, which was impacted by unrealized losses on oil and natural gas swaps of approximately $5.7 million due to increases in oil and natural gas prices from the end of the second quarter as well as $2.4 million of impairment. In the second quarter of 2009, we reported a net loss of $57.0 million, which included $75.8 million of unrealized losses on commodity derivatives.
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 November 4, 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 November 2009 through December 2013:
Annual Average Price
Calendar Year Volumes (Bbls) Price per Bbl Range per Bbl
----------------- -------------- ------------- ----------------
Oct. - Dec. 2009 372,394 $ 82.81 $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 550,025 $ 82.18 $80.10 - $89.35
2014 45,000 $ 90.50 $90.50
Average Price
Calendar Year Volumes (MMBtu) Price per MMBtu Range per MMBtu
---------------- --------------- ---------------- ---------------
Oct. - Dec. 2009 913,715 $ 7.45 $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)
----------------- ------------- ------------- -------------
Oct. - Dec. 2009 19,000 $ 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
------------------ --------------- ------------ -------------
Oct. - Dec. 2009 330,000 $ (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
----------------- ------------- -------------- ----------
Oct. - Dec. 2009 566,370 $ 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 September 30, 2009 Form 10-Q, which will be filed on or about November 6, 2009.
Conference Call
As announced on October 22, 2009, Legacy Reserves LP will host a teleconference and webcast to discuss Legacy's results on Thursday, November 5, 2009 at 2:00 p.m. (Central Time). Those wishing to participate in the conference call should dial 719-457-2080 or 888-378-0342. A replay of the call will be available through Monday, November 9, 2009, by dialing 719-457-0820 or 888-203-1112 and entering replay code 8246668. 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.
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.
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) and subsequent filings with the Securities and Exchange Commission. 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)
(In thousands, except per unit data)
Three Months Ended Nine Months Ended
-------------------- --------------------
Sept. 30, June 30, Sept. 30, Sept. 30,
2009 2009 2009 2008
--------- --------- --------- ---------
Revenues:
Oil sales $ 28,637 $ 24,604 $ 69,706 $ 132,400
Natural gas liquids
sales (NGL) 3,367 2,478 7,914 13,314
Natural gas sales 5,894 4,773 15,192 35,293
--------- --------- --------- ---------
Total revenues 37,898 31,855 92,812 181,007
--------- --------- --------- ---------
Expenses:
Oil and natural gas
production 12,517 11,468 35,988 38,827
Production and
other taxes 2,251 1,887 5,491 10,654
General and
administrative 4,001 3,900 11,269 8,872
Depletion,
depreciation,
amortization and
accretion 13,302 13,549 43,472 33,223
Impairment of
long-lived assets 2,375 452 3,982 447
Loss on disposal of
assets 26 31 265 391
--------- --------- --------- ---------
Total expenses 34,472 31,287 100,467 92,414
--------- --------- --------- ---------
Operating income
(loss) 3,426 568 (7,655) 88,593
Other income (expense):
Interest income 3 5 9 82
Interest expense (8,612) 1,761 (11,110) (7,164)
Equity in income of
partnerships 16 -- 13 135
Realized and
unrealized gain
(loss) on oil, NGL
and natural gas
swaps and oil collar 4,452 (59,172) (35,214) (54,873)
Other (1) 6 9 (28)
--------- --------- --------- ---------
Income (loss)
before income
taxes (716) (56,832) (53,948) 26,745
Income taxes (135) (160) (406) (628)
--------- --------- --------- ---------
Income (loss) from
continuing
operations (851) (56,992) (54,354) 26,117
Gain on sale of
discontinued
operation -- -- -- 4,954
--------- --------- --------- ---------
Net income (loss) $ (851) $(56,992) $(54,354) $ 31,071
========= ========= ========= =========
Income (loss) from
continuing
operations per
unit - basic and
diluted $ (0.03) $ (1.83) $ (1.74) $ 0.86
========= ========= ========= =========
Gain on discontinued
operation per unit
- basic and diluted $ -- $ -- $ -- $ 0.16
========= ========= ========= =========
Net income (loss)
per unit - basic
and diluted $ (0.03) $ (1.83) $ (1.74) $ 1.02
========= ========= ========= =========
Weighted average
number of units
used in computing
net income per
unit
basic 31,613 31,069 31,247 30,443
========= ========= ========= =========
diluted 31,613 31,069 31,247 30,492
========= ========= ========= =========
LEGACY RESERVES LP
CONSOLIDATED BALANCE SHEET (UNAUDITED)
(dollars in thousands)
Sept. 30,
2009
------------
ASSETS
Current assets:
Cash and cash equivalents $ 3,887
Accounts receivable, net:
Oil and natural gas 15,896
Joint interest owners 4,129
Other 11
Fair value of derivatives 27,037
Prepaid expenses and other current assets 2,610
------------
Total current assets 53,570
------------
Oil and natural gas properties, at cost:
Proved oil and natural gas properties,
using the successful efforts method of
accounting 840,458
Unproved properties 78
Accumulated depletion, depreciation and
amortization (252,521)
------------
588,015
------------
Other property and equipment, net of accumulated
depreciaton and amortization of $1,269 1,558
Operating rights, net of amortization of $1,841 5,176
Fair value of derivatives 34,703
Other assets, net of amortization of $2,317 4,788
Investment in equity method investee 29
------------
Total assets $ 687,839
============
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 1,576
Accrued oil and natural gas liabilities 16,052
Fair value of derivatives 9,833
Asset retirement obligation 4,272
Other 4,671
------------
Total current liabilities 36,404
------------
Long-term debt 230,000
Asset retirement obligation 79,297
Fair value of derivatives 6,667
Other long-term liabilities 48
------------
Total liabilities 352,416
------------
Commitments and contingencies
Unitholders' equity:
Limited partners' equity - 34,880,474 units
issued and outstanding at September 30, 2009 335,360
General partner's equity 63
------------
Total unitholders' equity 335,423
------------
Total liabilities and unitholders' equity $ 687,839
============
Selected Financial and Operating Data
(In thousands, except per unit data)
Three Months Ended Nine Months Ended
-------------------- --------------------
Sept. 30, June 30, Sept. 30, Sept. 30,
2009 2009 2009 2008
--------- --------- --------- ---------
Revenues:
Oil sales $ 28,637 $ 24,604 $ 69,706 $ 132,400
Natural gas liquid
sales 3,367 2,478 7,914 13,314
Natural gas sales 5,894 4,773 15,192 35,293
--------- --------- --------- ---------
Total revenue $ 37,898 $ 31,855 $ 92,812 $ 181,007
========= ========= ========= =========
Expenses:
Oil and natural
gas production $ 11,462 $ 10,671 $ 32,671 $ 36,005
Ad valorem taxes $ 1,055 $ 797 $ 3,317 $ 2,822
--------- --------- --------- ---------
Total oil and
natural gas
production
including ad
valorem taxes $ 12,517 $ 11,468 $ 35,988 $ 38,827
Production and
other taxes $ 2,251 $ 1,887 $ 5,491 $ 10,654
General and
administrative $ 4,001 $ 3,900 $ 11,269 $ 8,872
Depletion,
depreciation,
amortization and
accretion $ 13,302 $ 13,549 $ 43,472 $ 33,223
Realized swap
settlements:
Realized gain (loss)
on oil swaps $ 6,386 $ 12,683 $ 33,981 $(36,636)
Realized gain (loss)
on natural gas
liquid swaps $ 77 $ 202 $ 749 $ (3,092)
Realized gain on
natural gas swaps $ 3,663 $ 3,770 $ 11,030 $ (1,931)
Production:
Oil - barrels 438 441 1,339 1,191
Natural gas liquids
- gallons 4,084 3,843 11,316 8,843
Natural gas - Mcf 1,306 1,259 3,813 3,518
Total (MBoe) 753 742 2,244 1,988
Average daily
production (Boe/d) 8,185 8,154 8,220 7,255
Average sales price
per unit (excluding
swaps):
Oil price per barrel $ 65.38 $ 55.79 $ 52.06 $ 111.17
Natural gas liquid
price per gallon $ 0.82 $ 0.64 $ 0.70 $ 1.51
Natural gas price
per Mcf $ 4.51 $ 3.79 $ 3.98 $ 10.03
Combined (per Boe) $ 50.33 $ 42.93 $ 41.36 $ 91.05
Average sales price
per unit (including
realized swap
settlements):
Oil price per barrel $ 79.96 $ 84.55 $ 77.44 $ 80.41
Natural gas liquid
price per gallon $ 0.84 $ 0.70 $ 0.77 $ 1.16
Natural gas price
per Mcf $ 7.32 $ 6.79 $ 6.88 $ 9.48
Combined (per Boe) $ 63.78 $ 65.38 $ 61.75 $ 70.09
NYMEX oil index
prices per barrel:
Beginning of Period $ 69.89 $ 49.66 $ 44.60 $ 95.98
End of Period $ 70.61 $ 69.89 $ 70.61 $ 100.64
NYMEX gas index
prices per Mcf:
Beginning of Period $ 3.84 $ 3.78 $ 5.62 $ 7.48
End of Period $ 4.84 $ 3.84 $ 4.84 $ 7.72
Average unit costs
per Boe:
Oil and natural gas
production $ 15.22 $ 14.38 $ 14.56 $ 18.11
Ad valorem taxes $ 1.40 $ 1.07 $ 1.48 $ 1.42
Production and other
taxes $ 2.99 $ 2.54 $ 2.45 $ 5.36
General and
administrative $ 5.31 $ 5.26 $ 5.02 $ 4.46
Depletion,
depreciation,
amortization and
accretion $ 17.67 $ 18.26 $ 19.37 $ 16.71
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. 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:
(dollars in thousands)
Three Months Ended Nine Months Ended
-------------------- --------------------
Sept. 30, June 30, Sept. 30, Sept. 30,
2009 2009 2009 2008
--------- --------- --------- ---------
Net income (loss) $ (851) $(56,992) $(54,354) $ 31,071
Plus:
Interest expense
(income) 8,612 (1,761) 11,110 7,164
Income taxes 135 160 406 628
Depletion,
depreciation,
amortization and
accretion 13,302 13,549 43,472 33,223
Impairment of
long-lived assets 2,375 452 3,982 447
Gain on sale of assets (6) -- (66) (4,942)
Equity in income of
partnership (16) -- (13) (135)
Compensation expense
on LTIP and
restricted units 1,590 817 2,126 1,360
Unrealized loss on
oil and natural gas
swaps 5,674 75,827 80,974 13,214
--------- --------- --------- ---------
Adjusted EBITDA $ 30,815 $ 32,052 $ 87,637 $ 82,030
Less:
Cash interest
expense 4,492 4,655 14,102 6,591
LTIP settlements 66 59 302 98
Development
capital
expenditures 2,979 2,647 10,395 18,319
--------- --------- --------- ---------
Distributable Cash
Flow $ 23,278 $ 24,691 $ 62,838 $ 57,022
CONTACT: Legacy Reserves LP
Steven H. Pruett, President and Chief Financial Officer
432-689-5200
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