EXHIBIT 99.1
Legacy Reserves LP Announces Fourth Quarter and Year End 2008 Results
MIDLAND, Texas, March 4, 2009 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced annual and fourth quarter results for 2008. This unaudited financial information is preliminary and is subject to adjustments in connection with the final audited financial statements to be released on or about March 6, 2009 within Legacy's Annual Report on Form 10-K.
A summary of selected financial information follows. For consolidated financial statements, please see accompanying tables.
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Three Months Ended Twelve Months Ended
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Dec. 31, Sept. 30, December 31,
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2008 2008 2008 2007
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(dollars in millions)
Production (Boe/d) 8,553 7,587 7,582 4,970
Revenue $34.4 $65.6 $215.4 $112.2
Expenses $124.6 $35.8 $217.0 $75.6
Operating income (loss) ($90.2) $29.8 ($1.6) $36.7
Unrealized gain (loss) on
commodity swaps $230.4 $222.1 $217.2 ($85.4)
Net income (loss) $127.1 $228.0 $158.2 ($55.7)
Adjusted EBITDA (*) $17.7 $23.4 $99.9 $70.2
Distributable Cash Flow (*) $0.3 $10.0 $57.5 $48.5
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* Non-GAAP financial measure, see Adjusted EBITDA table at the end
of this press release
Highlights of the fourth quarter of 2008 compared to the third quarter of 2008:
* Adjusted EBITDA decreased 24% to $17.7 million from $23.4 million due to lower commodity prices in the period and the timing of commodity swap settlements. * Production increased 13% to 8,553 Boe per day from 7,587 Boe per day due to a combination of acquisitions and development drilling. * Net income of $127.1 million, or $4.09 per unit, was supported by $230.4 million of unrealized gains on our commodity derivatives offset by $76.5 million of impairment and DD&A of $30.1 million related to the dramatic reduction in oil and natural gas prices during the fourth quarter. Net income was $228.0 million in the third quarter which included $222.1 million of unrealized gains on our commodity derivatives. * Cash settlements received on our commodity swaps were $1.4 million compared to cash payments to our counterparties of $19.8 million in the third quarter.
Comparisons of 2008 results to 2007:
* Adjusted EBITDA increased 42% to $99.9 million from $70.2 million.
* Production increased 53% to 7,582 Boe per day from 4,970 Boe per
day.
* Net income was $158.2 million for the year, or $5.17 per unit,
compared to a loss of $55.7 million in 2007, or ($2.13) per unit.
Unrealized gains of $217.2 million were recorded on our commodity
derivatives in 2008 compared to unrealized losses of $85.4 million
in 2007.
* Proved reserves decreased 4% to 30.8 MMBoe from 32.1 MMBoe due to
the impact of lower year-end oil, natural gas liquids ("NGLs"),
and natural gas prices and elevated production and capital costs
based on the average costs from 2008, resulting in an 8.1 MMBoe
decrease in reserves.
* Year-end standardized measure of discounted future net cash flows
decreased 66% to $235.0 million from $690.5 million, with a $456.1
million reduction due to net changes in hydrocarbon sales prices
net of production costs. The standardized measure does not take
into account our oil, NGL and natural gas hedges.
* Distributions attributable to the fourth quarter 2008 were $0.52
per unit compared to $0.45 per unit attributable to the fourth
quarter 2007, a 15.6% increase.
Cary Brown, Chairman and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, said, "We delivered record fourth quarter production, and I am pleased with the rapid cost containment response of our operating team which was primarily responsible for a decrease of production costs from $22.61 per Boe in the third quarter to $16.74 per Boe in the fourth quarter including ad valorem taxes. Given current oil, NGL and natural gas prices, we expect production and capital costs to continue to fall in 2009.
"We acquired $50.2 million of properties in the fourth quarter, and we hedged approximately 85% of the related expected production at average prices of $108.90 per barrel of oil and $8.10 per MMBtu for ANR-Oklahoma natural gas for a period of four years. We invested $14.5 million in development projects, including drilling and completing 11 gross and 5.5 net wells."
Capital Program and Revised 2009 Budget
Mr. Brown continued, "While I am pleased with the performance of our third and fourth quarter development projects that contributed to a 966 Boe per day increase in quarterly production, we executed $25.4 million of projects in the second half of 2008 during a period of high capital costs and falling commodity prices. There was no way to predict the dramatic decline in oil, NGL and natural gas prices in the second half of the year, though the wells we drilled and completed in late 2008 are expected to have a long producing life. The elevated level of growth capital investment in the fourth quarter coupled with a $7.3 million unfavorable impact due to a one-month lag in the receipt of our oil and NGL commodity swap settlements resulted in 0.02 times coverage of our fourth quarter distribution. Given our maintenance capital target of 20% of Adjusted EBITDA, $3.5 million of our capital spending was maintenance capital with the $11 million balance considered discretionary growth capital. This would result in an adjusted distribution coverage of approximately 0.7 times our fourth quarter distribution. Our annual distribution coverage in 2008 was 0.94 times based on $32.8 million of development capital expenditures; however, if we consider only maintenance capital expenditures of an estimated $20 million, our 2008 annual distribution coverage would improve to 1.27 times.
"Our Board of Directors has approved a 2009 development capital budget of $20 million, reduced from $25 million previously announced. This is predicated on an improvement in oil and natural gas prices to $50 per barrel and $5.00 per MMBtu, respectively, by mid-year. Should prices continue to trade significantly below these levels, further reductions in our capital budget to $15 million will be considered. We have drilled two wells in the first quarter, but have no further plans to drill wells in the balance of the quarter or in the second quarter on properties we operate or have the ability to make an election on participation in drilling. We will continue to perform well workovers, recompletions, and restimulations in existing wellbores, which generally offer higher rates of return on capital than drilling and help us to offset natural decline. As capital costs are expected to continue to decline in 2009, and as we shift a larger portion of our capital investment from drilling to behind pipe and workover pr ojects, the productivity of our capital is expected to increase relative to 2008 when we experienced elevated costs and a higher percentage of our capital budget directed toward drilling projects."
Distribution Policy
Mr. Brown concluded, "We increased distributions from $0.41 per unit in our first full quarter following our initial public offering in January, 2007, to $0.52 per unit starting in the second quarter of 2008 and continuing through the fourth quarter of 2008. When we made the decision on July 22, 2008, to increase distributions to $0.52 per unit, oil and natural gas prices were over $120 per barrel and $10.00 per MMBtu, respectively. Our distribution coverage for the first and second quarters of 2008 was over 1.6 times.
"For 2009, our oil swaps and collars average $84.61 per barrel on approximately 72% of our 2009 expected oil production, and our natural gas swaps average $7.78 per MMBtu at Waha and ANR-Oklahoma indexes on over 64% of our expected 2009 natural gas production. We expect our cash flow from production and our hedges to provide coverage for our 2009 distribution and support our borrowing base on our credit facility. However, given the semi-annual borrowing base redeterminations that we are subject to, we continue to evaluate the best use of our cash flow to maintain liquidity. Should our borrowing base be lowered due to the potentially lower bank price forecasts, we may be required to reduce our outstanding debt. Reducing capital expenditures is our first step, and a second step could involve management's recommendation to the board to reduce our distributions to achieve the desired debt reduction."
Credit Facility Extension
Steven Pruett, President and Chief Financial Officer, commented on the anticipated extension of Legacy's Credit Agreement, "We are encouraged by the turnout at our bank group meeting on February 26, 2009 where we and our agent bank proposed an extension to our Credit Agreement which expires on March 15, 2010. We expect a reduction in our current borrowing base below the $410 million effective since November 26, 2008. We expect that the redetermined borrowing base will be in excess of our $300 million of debt outstanding on March 4, 2009. The turmoil in the financial markets has made it difficult for many lenders to extend credit; however, we expect to be successful in securing enough commitments from members of our bank group and potential new banks to extend the term of our Credit Agreement into 2012. We expect the cost and the terms of the extended credit facility to be less favorable than our current terms due to the tight credit markets. We expect both the interest rate margin and the upfront and commitm ent fees to increase significantly, but we do not expect a change in our restrictive covenants. Though our interest rate margin over LIBOR charged by our banks will increase, our unhedged cost of debt excluding the fees is expected to be approximately 3.5-4.5% based on current floating one and three month LIBOR rates of 0.5-1.5%. Our LIBOR swap position which expires during April through November of 2013 on $264 million of our debt averages 3.0%, thus our effective interest rate is expected to average approximately 6.0% on this hedged portion of our debt excluding fees. We expect the extension process of our Credit Agreement to be completed by the end of the first quarter."
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"). Legacy completed its Initial Public Offering and began trading on the NASDAQ Global Market under the ticker "LGCY" on January 12, 2007. The information discussed below is contained in operational data and financial statements at the end of this release.
Fourth Quarter 2008 Results Compared to Third Quarter 2008
Comparisons are made of the fourth quarter ended December 31, 2008 to the third quarter ended September 30, 2008, as it presents relevant sequential growth in performance measures.
Adjusted EBITDA
Adjusted EBITDA totaled $17.7 million in the fourth quarter compared to $23.4 million in the third quarter. The decrease is primarily attributable to falling oil and natural gas prices during the fourth quarter of 2008 and the one-month lag in receipt of our oil and NGL derivative settlements from our counterparties. Realized oil and natural gas prices averaged $54.58 and $4.77, respectively, in the fourth quarter of 2008 compared to $115.21 and $10.36 in the third quarter of 2008 resulting in a decrease in pricing of 53% on oil and 54% on natural gas. (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.)
Production
Net oil, NGL, and natural gas production increased to 8,553 Boe per day for the fourth quarter from 7,587 Boe per day in the third quarter. Our increased production in the fourth quarter resulted primarily from a combination of our acquisitions of oil and natural gas properties, from new wells drilled and completed as part of our ongoing development program, and from recompletion, restimulation, and reactivation projects completed in the third and fourth quarters of 2008.
Commodity Derivatives
We had a cash gain on commodity dervative settlements of $1.4 million in the fourth quarter 2008, compared to a cash loss of $19.8 million in the third quarter 2008. Our natural gas and NGL swap gains more than offset losses on our oil swaps for the fourth quarter 2008. We swapped 64% of our produced oil, NGL, and natural gas volumes in the fourth quarter and 71% in the third quarter of 2008. Legacy paid a net $1.5 million to its counterparties for its oil and NGL derivatives over the fourth quarter 2008, settling the calendar month contracts in the subsequent month, creating a one-month lag in settlements compared to the production month that is being hedged. This lag does not exist for natural gas derivatives as the floating price is set on the last three trading days prior to start of the production month. Legacy's cash payments for its oil and NGL hedges were $3.4 million in October for our September contracts, while our receipts in January 2009 for our December 2008 oil and NGL contracts were $3.9 milli on. The January receipts are recorded in the first quarter of 2009, though the contracts hedged our December production.
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.
Revenue and Commodity Prices
Oil, NGL and natural gas sales for the fourth and third quarter 2008 were $34.4 and $65.6 million, respectively, excluding the impact of any commodity derivative settlements. A 13% increase in sales volumes and a 53% decrease per Boe in commodity prices accounted for the decreased revenue.
Average oil and natural gas prices decreased significantly in the fourth quarter of 2008. Realized oil prices for the fourth and third quarters averaged $54.53 and $115.17 per barrel, respectively. Including the effect of cash losses on settled oil swaps, oil prices were $51.22 and $73.19 per barrel in the fourth and third quarters, respectively. Realized natural gas prices were $4.77 and $10.37 per Mcf for the fourth and third quarters, respectively. Including the effect of cash gains and losses on settled natural gas swaps, natural gas prices were $6.97 and $9.61 per Mcf for the same periods.
Costs
Production costs and ad valorem taxes, excluding severance taxes, for the fourth quarter 2008 declined to $16.74 per Boe from $22.61 per Boe for the third quarter. The decline was a result of reduced workover activity and the reduction in vendor costs as industry activity declined with lower commodity prices in the fourth quarter. General and administrative expenses increased during the fourth quarter to $3.21 per Boe from $3.09 per Boe in the third quarter due primarily to seasonal professional service fees for third party engineers, audit and legal fees. Depletion, depreciation and amortization costs increased to $38.25 per Boe in the fourth quarter from $18.74 per Boe in the third quarter due primarily to the reduction in reserves due to the substantially lower pricing environment in which our reserves were evaluated on December 31, 2008 compared to prices at September 30, 2008.
Net Income
Net income for the fourth quarter of 2008 was $127.1 million, which was favorably impacted by $230.4 million of net unrealized gains on the fair value of our future commodity swaps. In the third quarter, we recorded net income of $228.0 million, which was favorably impacted by $222.1 million of net unrealized gains on the fair value of our future commodity derivatives.
Year-End 2008 Results Compared to Year-End 2007
Adjusted EBITDA
Adjusted EBITDA increased to $99.9 million for the twelve months ending December 31, 2008, from $70.2 million for the twelve months ending December 31, 2007. This increase is primarily attributable to three factors: increased average prices year over year, oil and natural gas property acquisitions totaling $242.6 million (which includes asset retirement obligations ("ARO") of $25.0 million recorded with the acquisitions) during 2008 and finally by our capital development program.
Production
Net oil, NGL, and natural gas production averaged 7,582 Boe per day in 2008, increasing from 4,970 Boe per day in 2007. This is a result of our $242.6 million of proved property acquisitions (including $25.0 million of ARO) and $32.8 million of development capital investments in 2008 to drill, complete, recomplete, restimulate and workover wells.
Impact of Oil and Natural Gas Price Decline
We experienced a reduction in our proved reserves from 32.1 MMBoe at December 31, 2007 to 30.8 MMBoe at December 31, 2008, reflecting a downward revision of 8.1 MMBoe due to reduced oil, NGL and natural gas prices, the addition of 8.6 MMBoe through acquisitions (determined using December 31, 2008 NYMEX near month futures prices of $44.60 per Bbl and $5.62 per MMBtu for oil and natural gas, respectively) and 2008 total production of 2.775 MMBoe. Our standardized measure decreased to $235.0 million at December 31, 2008 from $690.5 million at December 31, 2007 due to the dramatic decline in oil, NGL and natural gas prices in the second half of 2008 to $44.60 per Bbl and $5.62 per MMBtu at year-end 2008, with $456.1 million of the reduction in standardized measure caused by the decline in commodity prices and higher production costs. Our proved reserve volumes and standardized measure are calculated based on these significantly lower year-end prices compared to year-end 2007 reference oil prices of $95.98 per Bb l and natural gas prices of $7.48 per MMBtu. Neither the decline in proved reserve volumes nor the decrease in standardized measure takes into account the fair market value of our commodity derivatives positions, which increased from a net liability of $82.3 million at December 31, 2007 to a $134.9 million net asset as of December 31, 2008. Further, unlike reserve volumes and the standardized measure, which are valued based on year-end prices, our operating and capital costs incurred over the prior twelve months were elevated due to higher industry activity levels and higher costs, such as electricity, steel and diesel fuel related to high oil and natural gas prices (which averaged $99.75 per Bbl and $8.90 per MMBtu for the year ended December 31, 2008). The mismatch between low year-end oil and natural gas prices (and as a result, the value of our reserves) and elevated operating and capital costs reduced our proved reserves to production ratio from 14 years at December 31, 2007 to approximately 10 years at December 31, 2008. Furthermore, based on current oil, NGL and natural gas prices, approximately 50% of our proved undeveloped reserves became uneconomic due to the elevated capital costs combined with the depressed oil and natural gas prices used to determine their value. If oil, NGL and natural gas prices improve from year-end 2008 levels, we would expect our reserve estimates to have positive revisions due to changes in prices.
Increase in Depletion, Depreciation, Amortization and Accretion
The severe loss in proved reserve volumes due to lower oil and natural gas prices increased our depletion, depreciation, amortization and accretion ("DD&A") expense. The DD&A rate is determined by the annual net hydrocarbon production divided by the sum of the year-end proved reserves and the annual production. Given that the year-end proved reserve balance has been reduced dramatically, the DD&A rate increased to $22.82 per Boe for the year ended December 31, 2008, from $15.66 per Boe for the year ended December 31, 2007. To the extent proved reserves are restored due to higher hydrocarbon prices in the future and/or lower production costs, the DD&A rate could reduce in the future. Similarly, should hydrocarbon prices and proved reserves decline further, the DD&A rate could increase further.
Impairment
As previously discussed, the combination of low year-end prices and increased production and capital costs reduced the calculated economic life of properties. The reduction in economic life and lower net revenues associated with lower hydrocarbon prices was the primary cause of impairment on 101 of our 239 fields, which amounted to $76.9 million for the year-ended December 31, 2008, an increase from $3.2 million for the year ended December 31, 2007. Legacy compares the net capitalized costs of proved oil and natural gas properties to the estimated undiscounted future net cash flows using management's expectations of future oil and natural gas prices. These future price scenarios reflect our estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the net capitalized costs are written down, or impaired, so that net capitalized costs equal the present value, discounted at 10%, of future net cash flows using management's expectations of future oil and natural gas prices.
Revenues and Realized Prices
For the twelve months ended December 31, 2008 and 2007, oil, NGL and natural gas sales were $215.4 million and $112.2 million, respectively.
For 2008 and 2007, average realized oil prices, excluding oil derivative contract settlements, were $95.16 and $70.65 per barrel, respectively. Including the effects of realized losses on our oil swaps, realized oil prices were $72.16 and $67.58 per barrel for the same periods. For 2008 and 2007, realized natural gas prices averaged $8.60 and $7.02 per Mcf, respectively. Including the effects of cash gains on our natural gas swaps, realized natural gas prices were $8.80 and $8.48 per Mcf for 2008 and 2007, respectively. The stated results are inclusive of natural gas basis swaps that we use to improve the effectiveness of our natural gas swaps.
For the year ended December 31, 2008, 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 West Texas Intermediate ("WTI") oil price of $72.80 per barrel and $8.14 per MMBtu, which is a combination of NYMEX Henry Hub, Waha (West Texas) and ANR-Oklahoma indexes. Legacy's realized prices are less than NYMEX WTI and Henry Hub natural gas due to quality and location differentials. One Mcf of natural gas sales equals approximately one MMBtu of swapped natural gas volumes after the natural gas is processed and NGL's are recovered at a plant.
Production Costs
For 2008 and 2007, production costs and ad valorem taxes, excluding production severance taxes, increased to $18.74 per Boe from $14.96 per Boe. The increase in production costs per Boe is primarily related to higher costs associated with higher average commodity prices in 2008.
General and Administrative Expenses ("G&A")
G&A expenses for 2008 decreased to $4.11 per Boe from $4.63 per Boe in 2007, due primarily to efficiencies achieved by increasing production relative to certain fixed costs including professional service fees that are not driven by wellcount. Although G&A expenses per barrel decreased, actual G&A expense increased $3.0 million year over year. Actual G&A expenses of $11.4 million in 2008 and $8.4 million in 2007 include $1.1 million and $1.0 million, respectively, of non-cash compensation expense on options and restricted units.
Net Income (Loss)
Net income for 2008 was $158.2 million, which was favorably impacted by $217.2 million of net unrealized gains on the fair value of our future commodity derivatives. In 2007, we recorded net loss of $55.7 million, which was unfavorably impacted by $85.4 million of net unrealized losses on our commodity derivatives. In 2008, we had $40.2 million of net cash losses on commodity derivative settlements, compared to $0.2 million of net cash gains on commodity derivative settlements in 2007.
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 March 2, 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 January, 2009 through December, 2013:
WTI: Calendar Annual Average Price Year Volumes (Bbls) Price per Bbl Range per Bbl -------- -------------- ------------- ---------------- 2009 1,488,969 $ 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 Natural Gas: Calendar Average Price Year Volumes (MMBtu) Price per MMBtu Range per MMBtu -------- --------------- ---------------- --------------- 2009 3,167,142 $ 8.06 $6.85 - $10.18 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 - $8.70
Additionally, we have entered into a costless collar for NYMEX WTI with the following attributes:
Calendar Annual Average Average Year Volumes (Bbl) Put ($/Bbl) Call ($/Bbl) -------- ------------- ----------- ------------ 2009 75,400 $ 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
Location and quality differentials attributable to our properties are not reflected in the above prices. The agreements provide for monthly settlement based on the difference between the agreement fixed price and the actual reference oil and natural gas index prices.
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 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:
Basis
Waha Basis Swaps Annual Average Differential
Calendar Year Volumes (MMBtu) Basis Differential per MMBtu
------------------ --------------- ------------------ ------------
2009 1,320,000 $ (0.68) $ (0.68)
2010 1,200,000 $ (0.57) $ (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:
Basis
ANR-OK Basis Swaps Annual Average Differential
Calendar Year Volumes (MMBtu) Basis Differential per MMBtu
------------------ --------------- ------------------ ------------
2009 480,000 $ (1.09) $ (1.09)
2010 480,000 $ (0.87) $ (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. 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 properties. 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
------------- ------------- ------------- ---------
2009 2,265,480 $ 1.15 $1.15
Annual Report on Form 10-K
The consolidated financial statements and related footnotes will be available in our December 31, 2008 Form 10-K, which will be filed on or about March 6, 2009.
Conference Call
As announced on February 24, 2009, Legacy Reserves LP will host an investor conference call to discuss Legacy's results on Thursday, March 5, 2009 at 3:30 p.m. (Central Time). Investors may access the conference call by dialing 877-852-6573. For those who cannot listen to the live broadcast, a replay of the call will be available through Monday, March 9, 2009, by dialing 719-457-0820 or 888-203-1112 and entering code 5406448, 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, 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 200 7 Annual Report on Form 10-K filed March 14, 2008, as amended (File No. 001-33249) and subsequently filed Quarterly Reports on Form 10-Q. 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 Twelve Months Ended
Dec. 31, Sept. 30, December 31,
--------- --------- -------------------
2008 2008 2008 2007
--------- --------- --------- ---------
(In thousands, except per unit data)
Revenues:
Oil sales $ 25,573 $ 47,912 $ 157,973 $ 83,301
Natural gas liquids sales
(NGL) 2,548 5,031 15,862 7,502
Natural gas sales 6,296 12,668 41,589 21,433
--------- --------- --------- ---------
Total revenues 34,417 65,611 215,424 112,236
--------- --------- --------- ---------
Expenses:
Oil and natural gas
production 13,177 15,784 52,004 27,129
Production and other taxes 2,058 4,096 12,712 7,889
General and administrative 2,524 2,158 11,396 8,392
Depletion, depreciation,
amortization and
accretion 30,102 13,082 63,324 28,415
Impairment of long-lived
assets 76,495 339 76,942 3,204
Loss on disposal of assets 211 317 602 527
--------- --------- --------- ---------
Total expenses 124,567 35,776 216,980 75,556
--------- --------- --------- ---------
Operating income (loss) (90,150) 29,835 (1,556) 36,680
Other income (expense):
Interest income 12 11 93 321
Interest expense (13,989) (4,198) (21,153) (7,118)
Equity in income (loss) of
partnerships (26) 47 108 77
Realized and unrealized
gain (loss) on oil, NGL
and natural gas swaps and
oil collar 231,816 202,388 176,943 (85,156)
Other 144 (9) 116 (129)
--------- --------- --------- ---------
Income (loss) before
income taxes 127,807 228,074 154,551 (55,325)
Income taxes 581 (122) (48) (337)
--------- --------- --------- ---------
Income (loss) from
continuing operations 128,388 227,952 154,503 (55,662)
Gain (loss) on sale of
discontinued operation (1,250) -- 3,704 --
Net income (loss) $ 127,138 $ 227,952 $ 158,207 $ (55,662)
========= ========= ========= =========
Income (loss) from
continuing operations per
unit - basic and diluted $ 4.13 $ 7.34 $ 5.05 $ (2.13)
========= ========= ========= =========
Gain (loss) on
discontinued operation
per unit - basic and
diluted $ (0.04)$ -- $ 0.12 $ --
========= ========= ========= =========
Net income (loss) per
unit - basic and diluted $ 4.09 $ 7.34 $ 5.17 $ (2.13)
========= ========= ========= =========
Weighted average number of
units used in computing
net income per unit
basic 31,049 31,041 30,596 26,155
========= ========= ========= =========
diluted 31,059 31,076 30,616 26,155
========= ========= ========= =========
LEGACY RESERVES LP
CONSOLIDATED BALANCE SHEET (UNAUDITED)
(dollars in thousands)
December 31,
2008
---------
ASSETS
Current assets:
Cash and cash equivalents $ 2,500
Accounts receivable, net:
Oil and natural gas 12,198
Joint interest owners 7,265
Other 60
Fair value of derivatives 54,820
Prepaid expenses and other current assets 4,094
---------
Total current assets 80,937
---------
Oil and natural gas properties, at cost:
Proved oil and natural gas properties, using the
successful efforts method of accounting 821,786
Unproved properties 78
Accumulated depletion, depreciation and
amortization (208,832)
---------
613,032
---------
Other property and equipment, net of accumulated
depreciaton and amortization of $765 and $251,
respectively 1,851
Operating rights, net of amortization of $1,429 and $865,
respectively 5,588
Fair value of derivatives 80,085
Other assets, net of amortization of $1,139 and
$391, respectively 1,558
Investment in equity method investee 21
---------
Total assets $ 783,072
=========
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 5,950
Accrued oil and natural gas liabilities 17,200
Fair value of derivatives 1,691
Asset retirement obligation 25,889
Other 6,276
---------
Total current liabilities 57,006
---------
Long-term debt 282,000
Asset retirement obligation 54,535
Fair value of derivatives 8,768
Other long-term liabilities 130
---------
Total liabilities 402,439
---------
Commitments and contingencies
Unitholders' equity:
Limited partners' equity - 31,049,299 units issued and
outstanding at December 31, 2008 380,509
General partner's equity 124
---------
Total unitholders' equity 380,633
---------
Total liabilities and unitholders' equity $ 783,072
=========
Selected Financial and Operating Data
Three Months Ended Twelve Months Ended
Dec. 31, Sept. 30, December 31,
--------- --------- --------- ---------
2008 2008 2008 2007
--------- --------- --------- ---------
(In thousands, except per unit data)
Revenues:
Oil sales $ 25,573 $ 47,912 $ 157,973 $ 83,301
Natural gas liquid sales 2,548 5,031 15,862 7,502
Natural gas sales 6,296 12,668 41,589 21,433
--------- --------- --------- ---------
Total revenue $ 34,417 $ 65,611 $ 215,424 $ 112,236
========= ========= ========= =========
Expenses:
Oil and natural gas
production $ 13,177 $ 15,784 $ 52,004 $ 27,129
Production and other taxes $ 2,058 $ 4,096 $ 12,712 $ 7,889
General and administrative $ 2,524 $ 2,158 $ 11,396 $ 8,392
Depletion, depreciation,
amortization and
accretion $ 30,102 $ 13,082 $ 63,324 $ 28,415
Realized swap settlements:
Realized gain (loss) on oil
swaps $ (1,549)$ (17,463)$ (38,185)$ (3,627)
Realized gain (loss) on
natural gas liquid swaps $ 67 $ (1,359)$ (3,025)$ (619)
Realized gain (loss) on
natural gas swaps $ 2,907 $ (928)$ 976 $ 4,458
Production:
Oil - barrels 469 416 1,660 1,179
Natural gas liquids -
gallons 4,134 3,301 12,977 5,295
Natural gas - Mcf 1,320 1,222 4,838 3,052
Total (MBoe) 787 698 2,775 1,814
Average daily production
(Boe/d) 8,553 7,587 7,582 4,970
Average sales price per unit:
Oil price per barrel $ 54.53 $ 115.17 $ 95.16 $ 70.65
Natural gas liquid price
per gallon $ 0.62 $ 1.52 $ 1.22 $ 1.42
Natural gas price per Mcf $ 4.77 $ 10.37 $ 8.60 $ 7.02
Combined (per Boe) $ 43.73 $ 94.00 $ 77.63 $ 61.87
Average sales price per unit
(including realized swap
settlements):
Oil price per barrel $ 51.22 $ 73.19 $ 72.16 $ 67.58
Natural gas liquid price
per gallon $ 0.63 $ 1.11 $ 0.99 $ 1.30
Natural gas price per Mcf $ 6.97 $ 9.61 $ 8.80 $ 8.48
Combined (per Boe) $ 45.54 $ 65.70 $ 63.13 $ 61.99
NYMEX oil index prices per
barrel:
Beginning of Period $ 100.64 $ 140.00 $ 95.98 $ 61.05
End of Period $ 44.60 $ 100.64 $ 44.60 $ 95.98
NYMEX gas index prices per
Mcf:
Beginning of Period $ 7.72 $ 13.35 $ 7.48 $ 6.30
End of Period $ 5.62 $ 7.72 $ 5.62 $ 7.48
Average unit costs per Boe:
Production costs, excluding
production and other
taxes $ 16.74 $ 22.61 $ 18.74 $ 14.96
Production and other taxes $ 2.61 $ 5.87 $ 4.58 $ 4.35
General and administrative $ 3.21 $ 3.09 $ 4.11 $ 4.63
Depletion, depreciation,
amortization and
accretion $ 38.25 $ 18.74 $ 22.82 $ 15.66
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; * Unrealized (gain) loss on oil and natural gas swaps.
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 Three Twelve Twelve
Months Months Months Months
Ended Ended Ended Ended
Dec. 31, Sept. 30, Dec. 31, Dec. 31,
--------- --------- --------- ---------
2008 2008 2008 2007
--------- --------- --------- ---------
(dollars in thousands)
Net income (loss) $ 127,138 $ 227,952 $ 158,207 $ (55,662)
Plus:
Interest expense 13,989 4,198 21,153 7,118
Income taxes (581) 122 48 337
Depletion, depreciation,
amortization and
accretion 30,102 13,082 63,324 28,415
Impairment of long-lived
assets 76,495 339 76,942 3,204
(Gain) loss on sale of
assets 1,223 -- (3,704) 387
Equity in (income) loss
of partnership 26 (47) (108) (77)
Compensation expense on
options and restricted
units (282) (117) 1,078 1,017
Unrealized (gain) loss on
oil and natural gas
swaps (230,390) (222,138) (217,176) 85,367
--------- --------- --------- ---------
Adjusted EBITDA $ 17,720 $ 23,391 $ 99,764 $ 70,106
Less:
Cash interest expense 2,859 2,805 9,451 5,085
Options settled 52 64 150 253
Development capital
expenditures 14,469 10,955 32,788 16,368
--------- --------- --------- ---------
Distributable Cash Flow $ 340 $ 9,567 $ 57,375 $ 48,400
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CONTACT: Legacy Reserves LP
Steven H. Pruett, President and Chief Financial Officer
432-689-5200