MIDLAND, Texas, Nov. 7, 2007 (PRIME NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced preliminary, unaudited third quarter results for 2007.
Cary Brown, Chairman and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, said, "Our third quarter results demonstrate the effect of our successful development program and include a full quarter of results from our four second quarter acquisitions and two months of results from the acquisition closed on August 3, 2007. We look forward to a full contribution in the fourth quarter from our two acquisitions which closed on October 1, 2007, with an aggregate purchase price of approximately $73.8 million. Our continuing strategy is to evaluate acquisition opportunities with a goal to make acquisitions that are accretive to our unitholders."
Summary of Third Quarter and Nine months Ended September 30, 2007 Results
This unaudited financial information is preliminary and is subject to adjustments in connection with the final unaudited financial statements to be released on or before November 14, 2007 within Legacy's Quarterly Report on Form 10-Q.
Net income (loss) for the three-month and nine-month periods ended September 30, 2007 totaled $2.2 and ($4.8) million, or $0.08 and ($0.19) basic and diluted earnings per unit, respectively, as compared to net income of $13.9 and $6.7 million, or $0.76 and $0.42 basic and diluted earnings per unit for the three-month and nine-month periods ended September 30, 2006, respectively. Financial results for the three and nine-month periods ended September 30, 2007 were unfavorably impacted by $6.8 million and $24.4 million, respectively, of net unrealized losses on our oil, natural gas liquids ("NGL") and natural gas swaps, as the fair value of our future derivative instruments was marked to market. Financial results for the three and nine-month periods ended September 30, 2006 were favorably impacted by $22.7 million and $7.7 million, respectively, of net unrealized gains on our oil and natural gas swaps, as the fair value of these derivative instruments was marked to market. Unrealized gains and losses represent current period mark-to-market adjustments for commodity derivatives which will be settled in future periods. Unrealized gains and losses result in a non-cash impact on revenue and do not affect our ability to make our expected cash distributions.
Adjusted EBITDA totaled $18.9 million and $44.6 million for the quarter and nine months ended September 30, 2007, respectively. (See "Non-GAAP Financial Measures" and the associated table for a discussion of management's use of Adjusted EBITDA in this release and a reconciliation of Legacy's consolidated net loss to Adjusted EBITDA.)
Financial and Operating Results:
Legacy was formed in October 2005 to own and operate the oil and natural gas properties it acquired from its Founding Investors in connection with the closing of a private equity offering on March 15, 2006 ("Formation Transaction"). Inasmuch as certain assets owned by the Founding Investors were acquired by Legacy on March 15, 2006, the results of operations and production volumes from these acquired assets are excluded from the first 73 days of the nine month period ended September 30, 2006.
Production
Net oil and natural gas production averaged 5,195 and 4,469 Boe per day for the quarter and nine months ended September 30, 2007, respectively, as compared to an average of 3,241 and 2,866 Boe per day for the quarter and nine months ended September 30, 2006. Legacy's increased production resulted primarily from a combination of its acquisition of oil and natural gas properties in the Formation Transaction, its 2006 and 2007 acquisitions of producing oil and natural gas properties, from new wells drilled and completed as part of its ongoing development program, and from recompletion, restimulation, and reactivation activities completed in the second and third quarters of 2007.
Revenues and Realized Prices
For the quarters ended September 30, 2007 and 2006, oil, NGL and natural gas sales were $29.4 million and $17.4 million, respectively. Revenues for the quarters ended September 30, 2007 and 2006, including net realized gains (losses) on our oil, NGL and natural gas swaps of $0.4 million and ($4.1) million, respectively, totaled $29.8 million and $13.3 million, respectively. Revenues including net realized and unrealized gains and losses on our oil, NGL and natural gas derivative contracts were $23.0 million and $36.0 million for the quarters ended September 30, 2007 and 2006, respectively.
For the nine months ended September 30, 2007 and 2006, oil, NGL and natural gas sales were $68.1 million and $43.3 million, respectively. Revenues for the nine months ended September 30, 2007 and 2006, including net realized gains (losses) on our oil, NGL and natural gas swaps of $4.2 million and ($2.2) million, respectively, totaled $72.3 million and $41.1 million, respectively. Revenues including net realized and unrealized gains and losses on our oil, NGL and natural gas derivative contracts were $47.9 million and $48.8 million for the nine months ended September 30, 2007 and 2006, respectively.
For the quarters ended September 30, 2007 and 2006, realized oil prices, excluding oil derivative contract settlements, were $71.83 and $65.06 per barrel, respectively. Including the effects of realized gains on our oil swaps, realized oil prices were $69.12 and $36.49 per barrel, respectively.
For the same periods, realized natural gas prices were $6.54 and $7.42 per Mcf excluding natural gas derivative contract settlements. Including the effects of realized gains on our natural gas swaps, realized natural gas prices were $8.26 and $10.34 per Mcf for the quarters ended September 30, 2007 and 2006, respectively.
For the quarter ended September 30, 2007, oil, NGL and natural gas derivative contracts, all of which are in the form of swaps, covered approximately 73% of Legacy's production at a weighted average NYMEX price of $62.82 per Boe. Legacy's realized prices are less than NYMEX West Texas Intermediate and Henry Hub natural gas due to quality and location differentials. The stated results are inclusive of natural gas basis swaps that we use to improve the effectiveness of our natural gas swaps.
For the nine months ended September 30, 2007 and 2006, realized oil prices, excluding oil derivative contract settlements, were $63.15 and $62.87 per barrel, respectively. Including the effects of realized gains on our oil swaps, realized oil prices were $64.62 and $49.50 per barrel. For the same periods, realized natural gas prices were $6.54 and $6.77 per Mcf excluding natural gas derivative contract settlements, respectively. Including the effects of realized gains on our natural gas swaps, realized natural gas prices were $8.05 and $9.72 per Mcf for the nine months ended September 30, 2007 and 2006, respectively.
For the nine months ended September 30, 2007, oil, NGL and natural gas derivative contracts, all of which are in the form of swaps, covered approximately 70% of Legacy's production at a weighted average NYMEX price of $63.86 per Boe. Legacy's realized prices are less than NYMEX West Texas Intermediate and Henry Hub natural gas due to quality and location differentials. The stated results are inclusive of natural gas basis swaps that we use to improve the effectiveness of our natural gas swaps.
Subsequent to September 30, 2007, oil futures prices have increased significantly. These increases in oil price futures will require us to make larger net settlement payments under commodity swap contracts. While these payments should not significantly affect our cash flow since payments made to counterparties to these contracts should be more than offset by increased commodity prices received on the sale of our production (some of which is unhedged), the increase in oil prices, should it continue, is expected to negatively affect the fair value of our oil and NGL swap contracts as recorded in our balance sheet at December 31, 2007 and during future periods and, consequently, our reported net earnings. Changes in the recorded fair value of commodity derivatives are marked to market through earnings and are likely to result in substantial non-cash charges to earnings for the decrease in the fair value of these contracts during the fourth quarter of 2007. If oil prices continue to increase, this negative non-cash effect on earnings will become more significant. We are currently unable to estimate the effects on earnings for the fourth quarter of 2007, but the effects may be substantial.
Production Costs
For the quarters ended September 30, 2007 and 2006, production costs and ad valorem taxes, excluding production severance taxes, totaled $7.6 million ($15.86 per Boe) and $4.2 million ($13.97 per Boe), respectively. The increase in production costs is primarily related to (i) $1.8 million of costs attributable to the Binger, Ameristate, TSF, Raven Shenandoah and Raven OBO acquisitions and (ii) $0.3 million related to increases in ad valorem tax expenses. In addition, the increase in production costs per Boe is consistent with industry-wide costs increases, particularly those related to oil operations that require lifting produced oil and water or involve enhanced recovery processes.
For the nine months ended September 30, 2007 and 2006, production costs and ad valorem taxes, excluding production severance taxes, totaled $18.4 million ($15.09 per Boe) and $10.2 million ($12.98 per Boe), respectively. The increase in production costs is primarily related to (i) $2.8 million attributable to the Binger, Ameristate, TSF, Raven Shenandoah and Raven OBO acquisitions, (ii) $0.8 million related to increase in ad valorem tax expenses, (iii) $1.3 million related to the exclusion of operating results for certain assets owned by the Founding Investors for the first 73 days of 2006 and not acquired until the Formation Transaction and, (iv) $1.6 million attributable to the South Justis, Farmer Field and Kinder Morgan acquisitions.
Depletion, Depreciation and Amortization (DD&A)
DD&A expense for the quarter ended September 30, 2007 totaled $7.0 million, or $14.56 per Boe, while DD&A expense was $5.3 million, or $17.93 per Boe, for the quarter ended September 30, 2006. The increase in DD&A is primarily related to $1.7 million of DD&A related to Binger, Ameristate, TSF, Raven Shenandoah and Raven OBO acquisitions. Our DD&A expense per Boe decreased due to the additional reserves added by our recent acquisitions. Under the successful efforts method of accounting, Legacy calculates DD&A on an individual producing field basis. Changes in reserve estimates and in the timing and amount of abandonment cost estimates as well as changes in the timing and amount of development projects of one or two fields can cause variations in the aggregate DD&A rate.
DD&A expense for the nine months ended September 30, 2007 totaled $19.1 million, or $15.63 per Boe, while DD&A expense was $12.7 million, or $16.23 per Boe, for the nine months ended September 30, 2006. The increase in DD&A is primarily related to (i) $2.7 million of DD&A related to recent acquisitions, (ii) $1.1 million of DD&A related to the Legacy Formation and, (iii) $1.6 million related to acquisitions made in the second quarter of 2006.
General and Administrative Expenses (G&A)
G&A expenses for the quarters ended September 30, 2007 and 2006 totaled $1.4 million ($3.02 per Boe) and $1.2 million ($3.98 per Boe), respectively. The $0.2 million increase in total G&A expenses reflects the growth of our asset base through acquisitions. The decrease in per BOE G&A expense reflects the growth of our asset base and related produced volumes through acquisitions.
G&A expenses for the nine months ended September 30, 2007 and 2006 totaled $6.0 million ($4.95 per Boe) and $3.3 million ($4.17 per Boe), respectively. The increase in G&A expense per Boe reflects both the higher costs of being a public entity and growth of our asset base through acquisitions. In addition, professional fees related to the filing of our tax returns and K-1's for our limited partners amounted to approximately $0.5 million for the nine months ended September 30, 2007. Expenses during the nine months ended September 30, 2007 for professional fees related to the audit of our December 31, 2006 financial statements amounted to approximately $254,000. In addition, unit-based compensation expenses increased $0.9 million due to a $0.6 million non-cash expense related to the change in the estimated fair value of our unit-based compensation liability and $0.3 million of cash payments to employees exercising unit options.
Oil, NGL and Natural Gas Derivative Instruments
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 7, 2007, 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 October, 2007 through December, 2012:
Calendar Annual Average Price
Year Volumes (Bbls) Price per Bbl Range per Bbl
-------- ------------- ------------- ---------------
2007 273,578 $ 68.81 $64.15 - $75.70
2008 1,025,249 $ 68.57 $62.25 - $73.45
2009 948,013 $ 66.65 $61.05 - $71.40
2010 883,445 $ 65.26 $60.15 - $71.15
2011 665,040 $ 70.17 $67.33 - $71.40
2012 549,600 $ 70.04 $67.72 - $71.15
Calendar Annual Average Price
Year Volumes (Mcf) Price per Mcf Range per Mcf
-------- ------------- ------------- ---------------
2007 656,192 $ 8.59 $6.85 - $10.01
2008 2,402,970 $ 8.17 $6.85 - $10.58
2009 2,217,470 $ 8.01 $6.85 - $10.18
2010 1,962,755 $ 7.74 $6.85 - $9.73
2011 694,024 $ 7.21 $6.85 - $7.51
2012 404,436 $ 7.07 $6.85 - $7.30
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 price and the actual reference oil and natural gas index prices.
We have entered into 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 natural gas sales follow Waha more closely than NYMEX. The basis swaps thereby provide a better correlation between our natural gas sales and the settlement payments on our natural gas swaps. The following table summarizes, for the periods indicated, our NYMEX basis swaps currently in place for production months through December 31, 2010:
Annual Basis Differential
Calendar Year Volumes (Mcf) per Mcf
------------- ------------- ------------------
2007 390,000 ($0.88)
2008 1,422,000 ($0.84)
2009 1,320,000 ($0.68)
2010 1,200,000 ($0.57)
On March 30, 2007 and September 7, 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. We entered into these swaps to offset cash flow volatility from the NGL sales from our interests in the East Binger (Marchand) Unit in Caddo County, Oklahoma, and our Texas Panhandle acquisition that closed on October 1, 2007. The following table summarizes, for the periods indicated, our Mont Belvieu, Non-Tet OPIS natural gas liquids swaps currently in place for production months through December 31, 2009.
Calendar Annual Average Price Year Volumes (Gal) Price per Gal Range per Gal -------- ------------- ------------- ------------- 2007 1,682,838 $ 1.32 $0.79 - $1.68 2008 6,458,004 $ 1.27 $0.66 - $1.62 2009 2,265,480 $ 1.15 $1.15
Quarterly Report on Form 10-Q
The consolidated financial statements and related footnotes will be available in our September 30, 2007 Form 10-Q, which will be filed on or before November 14, 2007.
Conference Call
As announced on October 31, 2007, Legacy Reserves LP will host an investor conference call to discuss Legacy's results on Thursday, November 8, 2007 at 3:00 p.m. (Central Time). Investors may access the conference call by dialing 888-300-2342. For those who cannot listen to the live broadcast, a replay of the call will be available through Monday, November 12, 2007, by dialing 719-457-0820 or 888-203-1112 and entering code 3322147, or by going to the Investor Relations tab of Legacy's website (www.LegacyLP.com). We will take live questions from securities analysts and institutional portfolio managers and analysts; the complete call is open to all other interested parties on a listen-only basis.
About Legacy Reserves LP
We are an independent oil and natural gas limited partnership headquartered in Midland, Texas, and are focused on the acquisition and exploitation of oil and natural gas properties primarily located in the Permian Basin of West Texas and southeast New Mexico and the Mid-Continent regions. 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 2006 Annual Report on Form 10-K filed March 28, 2007 (File No. 333-138637). 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 Nine Months Ended
September 30, September 30,
------------------------- --------------------------
2006(a) 2007 2006(a) 2007
----------- ----------- ----------- ------------
Revenues:
Oil sales $13,204,380 $22,441,858 $32,443,950 $ 51,396,169
Natural gas
liquid sales -- 1,713,657 -- 2,890,994
Natural gas
sales 4,238,937 5,240,788 10,822,193 13,776,326
Realized and
unrealized gain
(loss) on oil
and natural
gas swaps 18,605,638 (6,435,752) 5,533,553 (20,151,656)
----------- ----------- ----------- ------------
Total
revenues 36,048,955 22,960,551 48,799,696 47,911,833
----------- ----------- ----------- ------------
Expenses:
Oil and
natural gas
production 4,166,766 7,580,473 10,159,887 18,408,152
Production and
other taxes 1,029,511 1,886,122 2,710,392 4,360,881
General and
adminis-
trative 1,186,884 1,443,190 3,265,163 6,039,371
Depletion,
depreciation,
amortization
and accretion 5,346,432 6,959,351 12,701,726 19,065,064
Impairment of
long-lived
assets 8,572,859 950,174 8,572,859 1,229,874
Loss on dis-
posal of
assets -- 156,240 -- 387,373
----------- ----------- ----------- ------------
Total
expenses 20,302,452 18,975,550 37,410,027 49,490,715
----------- ----------- ----------- ------------
Operating
income
(loss) 15,746,503 3,985,001 11,389,669 (1,578,882)
Other income
(expense):
Interest
income 55,226 54,284 93,659 205,443
Interest
expense (1,857,331) (1,905,234) (4,511,679) (3,423,286)
Equity in
income (loss)
of partner-
ships -- 29,690 (317,788) 40,600
Other -- -- 14,910 1,013
----------- ----------- ----------- ------------
Net income
(loss) $13,944,398 $ 2,163,741 $ 6,668,771 $ (4,755,112)
=========== =========== =========== ============
Net income
(loss) per unit
- basic and
diluted $ 0.76 $ 0.08 $ 0.42 $ (0.19)
=========== =========== =========== ============
Weighted average
number of units
used in comput-
ing net income
(loss) per
unit -
basic 18,386,817 26,021,518 15,952,509 25,492,521
=========== =========== =========== ============
diluted 18,386,817 26,072,886 15,952,509 25,492,521
=========== =========== =========== ============
(a) Inasmuch as certain assets owned by the Founding Investors were
acquired by Legacy on March 15, 2006, the results of operations
of these acquired assets are excluded from the first 73 days of
the three months ended March 31, 2006
LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEET (UNAUDITED)
September 30,
2007
-------------
ASSETS
Current assets:
Cash and cash equivalents $ 4,358,522
Accounts receivable, net:
Oil and natural gas 12,596,594
Joint interest owners 3,650,636
Affiliated entities and other 9,907
Fair value of derivatives 301,534
Prepaid expenses and other current assets 649,654
-------------
Total current assets 21,566,847
-------------
Oil and natural gas properties, at cost:
Proved oil and natural gas properties, using the
successful efforts method of accounting 406,356,304
Unproved properties 78,025
Accumulated depletion, depreciation and amortization (61,373,332)
-------------
345,060,997
-------------
Other property and equipment, net 679,495
Deposit on pending acquisitions 4,637,644
Operating rights, net 6,291,730
Fair value of derivatives 25,293
Other assets, net 738,235
Investment in equity method investee 86,731
-------------
$ 379,086,972
=============
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 681,293
Accrued oil and natural gas liabilities 8,566,783
Fair value of derivatives 8,124,905
Asset retirement obligation 470,518
Other 2,882,551
-------------
Total current liabilities 20,726,050
Long-term debt 93,000,000
Fair value of derivatives 7,045,527
Asset retirement obligation 13,768,328
-------------
Total liabilities 134,539,905
-------------
Commitments and contingencies
Unitholders' equity:
Limited partners' equity - 26,021,518 units
issued and outstanding at September 30, 2007 244,440,705
General partner's equity 106,362
-------------
Total unitholders' equity 244,547,067
-------------
Total liabilities and unitholders' equity $ 379,086,972
=============
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- --------------------------
2006 2007 2006 (a) 2007
----------- ----------- ----------- ------------
Revenues:
Oil sales $13,204,380 $22,441,858 $32,443,950 $ 51,396,169
Natural gas
liquid sales -- 1,713,657 -- 2,890,994
Natural gas
sales 4,238,937 5,240,788 10,822,193 13,776,326
Realized gain
(loss) on oil
swaps (5,798,140) (845,744) (6,897,833) 1,198,916
Realized loss
on natural
gas liquid
swaps -- (118,044) -- (159,395)
Realized gain
on natural
gas swaps 1,669,838 1,372,154 4,715,768 3,196,205
Unrealized
gain (loss)
on oil swaps 19,770,172 (7,677,256) 1,342,276 (20,860,444)
Unrealized
loss on
natural gas
liquid swaps -- (650,285) -- (940,557)
Unrealized
gain (loss)
on natural
gas swaps 2,963,768 1,483,423 6,373,342 (2,586,381)
----------- ----------- ----------- ------------
Total
revenue $36,048,955 $22,960,551 $48,799,696 $ 47,911,833
=========== =========== =========== ============
Expenses:
Oil and
natural gas
production $ 4,166,766 $ 7,580,473 $10,159,887 $ 18,408,152
Production
and other
taxes $ 1,029,511 $ 1,886,122 $ 2,710,392 $ 4,360,881
General and
administra-
tive $ 1,186,884 $ 1,443,190 $ 3,265,163 $ 6,039,371
Depletion,
depreciation,
amortization
and
accretion $ 5,346,432 $ 6,959,351 $12,701,726 $ 19,065,064
Production:
Oil - barrels 202,952 312,433 516,057 813,906
Natural gas
liquids -
gallons -- 1,344,553 -- 2,303,892
Natural gas
- Mcf 571,246 800,936 1,598,909 2,107,376
Total (Boe) 298,160 477,936 782,542 1,219,990
Average daily
production
(Boe/d) 3,241 5,195 2,866 4,469
Average sales
price per unit
(including
hedges):
Oil price per
barrel $ 133.91 $ 44.55 $ 52.10 $ 38.99
Natural gas
liquid price
per gallon $ -- $ 0.70 $ -- $ 0.78
Natural gas
price per
Mcf $ 15.53 $ 10.11 $ 13.70 $ 6.83
Combined
(per Boe) $ 120.90 $ 48.04 $ 62.36 $ 39.27
Average sales
price per unit
(including
realized hedge
gains/losses):
Oil price per
barrel $ 36.49 $ 69.12 $ 49.50 $ 64.62
Natural gas
liquid price
per gallon $ -- $ 1.19 $ -- $ 1.19
Natural gas
price per
Mcf $ 10.34 $ 8.26 $ 9.72 $ 8.05
Combined
(per Boe) $ 44.66 $ 62.36 $ 52.50 $ 59.26
Average sales
price per unit
(excluding
hedges):
Oil price per
barrel $ 65.06 $ 71.83 $ 62.87 $ 63.15
Natural gas
liquid price
per gallon $ -- $ 1.27 $ -- $ 1.25
Natural gas
price per
Mcf $ 7.42 $ 6.54 $ 6.77 $ 6.54
Combined
(per Boe) $ 58.50 $ 61.51 $ 55.29 $ 55.79
NYMEX oil index
prices per
barrel:
Beginning of
Period $ 73.93 $ 70.68 $ 61.04 $ 61.05
End of Period $ 62.91 $ 81.66 $ 62.91 $ 81.66
NYMEX gas index
prices per Mcf:
Beginning of
Period $ 6.10 $ 6.77 $ 11.18 $ 6.30
End of Period $ 5.62 $ 6.87 $ 5.62 $ 6.87
Average unit
costs per Boe:
Production
costs, ex-
cluding pro-
duction and
other taxes $ 13.97 $ 15.86 $ 12.98 $ 15.09
Production and
other taxes $ 3.45 $ 3.95 $ 3.46 $ 3.57
General and
administra-
tive $ 3.98 $ 3.02 $ 4.17 $ 4.95
Depletion,
depreciation,
amortization
and
accretion $ 17.93 $ 14.56 $ 16.23 $ 15.63
(a) Inasmuch as certain assets owned by the Founding Investors were
acquired by Legacy on March 15, 2006, the results of operations
of these acquired assets are excluded from the first 73 days of
the three months ended March 31, 2006.
Non-GAAP Financial Measure
This press release, the financial tables and other supplemental information, including the reconciliation of "Adjusted EBITDA", a non-generally accepted accounting principles ("non-GAAP") measure to its nearest comparable generally accepted accounting principles ("GAAP") measure, may be used periodically by management when discussing our financial results with investors and analysts and they are also available on our website under the Investor Relations tab.
"Adjusted EBITDA" should not be considered as an alternative 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;
* Depletion, depreciation, amortization and accretion;
* Impairment of long-lived assets;
* (Gain) loss on sale of partnership investment;
* (Gain) loss on sale of assets;
* Stock-based compensation expense arising from
equity-based awards;
* Equity in (income) loss of partnerships; and
* Unrealized (gain) loss on oil and natural gas swaps
Adjusted EBITDA is presented as management believes it provides 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 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 loss to Adjusted EBITDA:
Three Months Ended Nine Months Ended
September 30, September 30,
------------ ------------
2007 2007
------------ ------------
Net income (loss) $ 2,163,741 $ (4,755,112)
Plus:
Interest expense 1,905,234 3,423,286
Depletion, depreciation,
amortization and accretion 6,959,351 19,065,064
Impairment of long-
lived assets 950,174 1,229,874
Loss on sale of assets 156,240 387,373
Compensation expense on
options and restricted units (123,960) 887,920
Unrealized loss on oil, NGL
and natural gas swaps 6,844,117 24,387,381
------------ ------------
Adjusted EBITDA $ 18,854,897 $ 44,625,786
============ ============