EXHIBIT 99.1
Legacy Reserves LP Announces First Quarter 2010 Results
MIDLAND, Texas, May 5, 2010 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced first quarter results for 2010. The final unaudited Quarterly Report will be released on or about May 7, 2010.
A summary of selected financial information follows. For consolidated financial statements, please see accompanying tables.
| | Three Months Ended |
| (Dollars in millions except as noted below) | March 31, | December 31, | March 31, |
| | 2010 | 2009 | 2009 |
| | (dollars in millions) |
| Production (Boe/d) | 8,767 | 8,250 | 8,322 |
| Revenue | $49.7 | $44.5 | $23.1 |
| Commodity Derivative Cash Settlements | $4.8 | $6.7 | $19.0 |
| Expenses | $43.8 | $40.3 | $34.7 |
| Operating income (loss) | $5.9 | $4.2 | ($11.6) |
| Unrealized gain (loss) on commodity derivatives | $7.1 | ($47.0) | $0.5 |
| Net income (loss) | $10.2 | ($38.5) | $3.5 |
| Adjusted EBITDA (*) | $32.7 | $32.4 | $24.8 |
| Development Capital | $5.2 | $3.3 | $3.0 |
| Distributable Cash Flow (*) | $22.1 | $25.2 | $14.9 |
| * Non-GAAP financial measure, see Adjusted EBITDA and Distributable Cash Flow table at the end of this press release |
Highlights of the first quarter of 2010 compared to the fourth quarter of 2009:
- Production increased 6% to 8,767 Boe per day from 8,250 Boe per day due to a combination of acquisitions and development projects, partially offset by weather-related power outages and third party gathering system downtime in the Texas Panhandle.
- Oil, natural gas liquids ("NGL") and natural gas sales, excluding commodity derivatives settlements, were $49.7 million, up 12% from $44.5 million in the fourth quarter due to both increased production and higher realized prices.
- Combined realized prices were $62.95 per Boe in the first quarter, up 7% from $58.59 per Boe in the fourth quarter. Realized oil prices were $74.90 per barrel compared to $72.91 per barrel, while average realized natural gas prices increased to $6.72 per Mcf from $5.80 per Mcf.
- Production expenses, excluding taxes, increased to $14.2 million, or $17.94 per Boe, from $11.6 million, or $15.33 per Boe, due to acquisition of additional producing properties and cost escalation related to higher oil and natural gas prices.
- General and administrative costs increased to $4.8 million, or $6.03 per Boe, in the first quarter from $4.2 million, or $5.58 per Boe, in the fourth quarter of 2009 due primarily to seasonal professional service fees related to year-end audit, tax, legal and reserve report preparation. Non-cash compensation expense, tied to employee's Long Term Incentive Program ("LTIP"), contributed $1.0 million ($1.30 per Boe) in the first quarter of 2010 and $1.0 million ($1.32 per Boe) in the fourth quarter of 2009.
- Cash settlements received on our commodity derivatives were $4.8 million compared to cash settlements of $6.7 million in the fourth quarter of 2009. Our production was 80% hedged in the first quarter compared to 73% in the fourth quarter. We reported an unrealized gain of $7.1 million on our commodity derivatives portfolio in the first quarter compared to an unrealized loss of $47.1 million in the fourth quarter.
- Adjusted EBITDA was $32.7 million, up from $32.4 million in the prior quarter due to increased production and higher commodity prices. (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 income to Adjusted EBITDA).
- Development capital expenditures increased to $5.2 million from $3.3 million in the fourth quarter of 2009 as we commenced our 2010 drilling program.
- Distributable cash flow decreased to $22.1 million from $25.2 million as a result of increased development capital expenditures and cash settlements on employee LTIP awards of $1.7 million.
- Distributable cash flow per unit decreased to $0.55 per unit from $0.63 per unit in the fourth quarter of 2009 due to lower distributable cash flow and increased unit count as a result of our January issuance of 4,887,500 units. We paid a distribution of $0.52 per unit on 40,070,201 units on February 12, 2010.
- Net income of $10.2 million, or $0.26 per unit, was favorably impacted by $7.1 million of unrealized gains on our commodity derivatives offset by $7.9 million of impairment primarily on our natural gas properties. We incurred a net loss of $38.5 million in the fourth quarter of 2009 which was a result of $47.1 million of unrealized losses on our commodity derivatives and an impairment expense of $5.2 million.
Cary D. Brown, Chairman and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, commented: "We have had a great start to 2010 with over $154 million of oil and gas properties acquired or under contract. In the first quarter, we issued 4,887,500 units receiving net proceeds of $95.4 million which we used to fund our largest acquisition to date; our $125 million purchase of oil and gas properties in Wyoming on February 17, 2010. Additionally, we opened a business unit office in Cody, Wyoming to manage our Wyoming assets and grow our business in the Rockies. Our operations and administrative teams are in the process of integrating the new assets, and we have been very pleased with the results of their efforts. We increased production in the first quarter to 8,767 Boe per day from 8,250 Boe per day in the prior quarter due to our recent acquisitions as well as successful development capital projects. We are pleased to report that during the first qua rter we generated $0.55 per unit of distributable cash flow, covering our $0.52 distribution 1.06 times despite owning and receiving benefits from our Wyoming acquisition for only 41 days (46%) of the quarter and having increased our development capital expenditures to $5.2 million. We have increased our capital budget for 2010 to $31 million from $13.7 million in 2009 to take advantage of strong economic returns offered by our oil drilling and recompletion projects."
Steven Pruett, President and Chief Financial Officer, commented, "On March 31st, our bank group increased our borrowing base to $410 million from $340 million. In addition to the increased borrowing base, we added two new banks to our syndicate, which now has eleven banks. We have $146 million of borrowing capacity under our credit facility. We are excited about our deal flow and expect to close additional acquisitions during the balance of 2010."
Commodity Derivatives
We have entered into the following fixed price swaps for oil and natural gas to help mitigate the risk of changing commodity prices. As of May 5, 2010, we had entered into swap agreements to receive average NYMEX West Texas Intermediate oil and Henry Hub, Waha, ANR-Oklahoma, and CIG-Rockies natural gas prices as summarized below starting with April, 2010 through December, 2014:
WTI:
| | Annual | Average | Price |
| Calendar Year | Volumes (Bbls) | Price per Bbl | Range per Bbl |
| April - December 2010 | 1,454,957 | $ 81.89 | $60.15 - $140.00 |
| 2011 | 1,625,812 | $ 86.99 | $67.33 - $140.00 |
| 2012 | 1,324,466 | $ 82.01 | $67.72 - $109.20 |
| 2013 | 881,445 | $ 83.62 | $80.10 - $89.35 |
| 2014 | 356,710 | $ 87.88 | $87.50 - $90.50 |
On May 3, 2010, we entered into two separate NYMEX West Texas Intermediate crude oil derivative three-way collar contracts. Each contract combines a long and short put with a short call. The use of the long put combined with the short put allows us to purchase a short call at a higher price thus establishing a higher ceiling and limiting our exposure to future settlement payments while also restricting our downside coverage to the difference between the long put and the short put if the price of NYMEX West Texas Intermediate crude oil drops below the price of the short put. This allows us to settle for WTI market price plus the spread between the short put and the long put in a case where the market price has fallen below the short put fixed price, or the floating price plus $25 per barrel ($85-$60). The following table summarizes the three-way oil collar contracts currently in place as of May 5, 2010, through June 30, 2015:
Calendar Year |
Volumes (Bbls) | Short Put
($/Bbl) | Long Put
($/Bbl) | Short Call
($/Bbl) |
| July 2013 - June 2014 | 65,700 | $ 60.00 | $ 85.00 | $ 124.00 |
| July 2014 - June 2015 | 146,000 | $ 60.00 | $ 85.00 | $ 130.05 |
Additionally, we have entered into a costless collar for NYMEX WTI with the following attributes:
| | Annual | Average | Average |
| Calendar Year | Volumes (Bbl) | Put ($/Bbl) | Call ($/Bbl) |
| April - December 2010 | 54,100 | $ 120.00 | $ 156.30 |
| 2011 | 68,300 | $ 120.00 | $ 156.30 |
| 2012 | 65,100 | $ 120.00 | $ 156.30 |
Natural Gas:
| | | Average | Price |
| Calendar Year | Volumes (MMBtu) | Price per MMBtu | Range per MMBtu |
| April - December 2010 | 2,947,044 | $ 7.09 | $5.33 - $8.88 |
| 2011 | 3,038,316 | $ 7.49 | $5.74 - $8.70 |
| 2012 | 2,357,990 | $ 7.49 | $5.72 - $8.70 |
| 2013 | 1,402,754 | $ 6.58 | $5.78 - $6.89 |
| 2014 | 609,104 | $ 6.36 | $5.95 - $6.47 |
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:
| Waha Basis Swaps | Annual | Basis Differential |
| Calendar Year | Volumes (MMBtu) | per MMBtu |
| April - December 2010 | 900,000 | $ (0.57) |
Quarterly Report on Form 10-Q
The consolidated financial statements and related footnotes will be available in our March 31, 2010 Form 10-Q, which will be filed on or about May 7, 2010.
Conference Call
As announced on April 26, 2010, Legacy Reserves LP will host an investor conference call to discuss Legacy's results on Thursday, May 6, 2010 at 8:30 a.m. (Central Time). Investors may access the conference call by dialing 877-266-0479. For those who cannot listen to the live broadcast, a replay of the call will be available through Monday, May 10, 2010, by dialing 706-645-9291 or 800-642-1687 and entering code 71595782, 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
Legacy Reserves LP is 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, Mid-continent and Rocky Mountain 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 our annual and quarterly reports filed with the SEC. Therefore, ac tual 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 |
| | March 31, | December 31, | March 31, |
| | 2010 | 2009 | 2009 |
| | (In thousands, except per unit data) |
| Revenues: | | | |
| Oil sales | $ 37,748 | $ 33,613 | $ 16,465 |
| Natural gas liquids (NGL) sales | 3,750 | 3,651 | 2,069 |
| Natural gas sales | 8,169 | 7,203 | 4,525 |
| | -- | -- | |
| Total revenues | 49,667 | 44,467 | 23,059 |
| | | | |
| Expenses: | | | |
| Oil and natural gas production | 15,070 | 12,827 | 12,002 |
| Production and other taxes | 2,919 | 2,654 | 1,353 |
| General and administrative | 4,761 | 4,233 | 3,368 |
| Depletion, depreciation, amortization and accretion | 13,115 | 15,291 | 16,621 |
| Impairment of long-lived assets | 7,916 | 5,224 | 1,156 |
| Loss on disposal of assets | 14 | 113 | 208 |
| | | | |
| | | | |
| Total expenses | 43,795 | 40,342 | 34,708 |
| | | | |
| Operating income (loss) | 5,872 | 4,125 | (11,649) |
| | | | |
| Other income (expense): | | | |
| Interest income | 3 | -- | 1 |
| Interest expense | (7,333) | (2,112) | (4,259) |
| Equity in income (loss) of partnerships | 23 | 17 | (2) |
| Realized and unrealized net gains (losses) on | | | |
| commodity derivatives | 11,861 | (40,339) | 19,505 |
| Other | (33) | (20) | 4 |
| | | | |
| Income (loss) before income taxes | 10,393 | (38,329) | 3,600 |
| | | | |
| Income taxes | (173) | (148) | (111) |
| | | | |
| Net income (loss) | $ 10,220 | $ (38,477) | $ 3,489 |
| | | | |
| Net income (loss) per unit -- | | | |
| basic and diluted | $ 0.26 | $ (1.10) | $ 0.11 |
| | | | |
| Weighted average number of units used in computing | | | |
| net income per unit | | | |
| Basic | 39,216 | 34,880 | 31,053 |
| | | | |
| Diluted | 39,219 | 34,880 | 31,067 |
| |
| LEGACY RESERVES LP |
| CONDENSED CONSOLIDATED BALANCE SHEET (UNAUDITED) |
| (dollars in thousands) |
| | March 31, |
| | 2010 |
| ASSETS | |
| Current assets: | |
| Cash and cash equivalents | $ 6,114 |
| Accounts receivable, net: | |
| Oil and natural gas | 23,841 |
| Joint interest owners | 4,461 |
| Other | 343 |
| Fair value of derivatives | 19,607 |
| Prepaid expenses and other current assets | 2,162 |
| | |
| Total current assets | 56,528 |
| | |
| Oil and natural gas properties, at cost: | |
| Proved oil and natural gas properties, using the | |
| successful efforts method of accounting | 983,030 |
| Unproved properties | 7,258 |
| Accumulated depletion, depreciation and amortization | (291,797) |
| | 698,491 |
| Other property and equipment, net of accumulated depreciaton and | |
| amortization of $1,631 | 1,376 |
| Deposit on pending acquisition | 700 |
| Operating rights, net of amortization of $2,116 | 4,901 |
| Fair value of derivatives | 12,203 |
| Other assets, net of amortization of $3,245 | 4,245 |
| Investment in equity method investee | 70 |
| | |
| Total assets | $ 778,514 |
| | |
| LIABILITIES AND UNITHOLDERS' EQUITY | |
| Current liabilities: | |
| Accounts payable | $ 2,225 |
| Accrued oil and natural gas liabilities | 19,224 |
| Fair value of derivatives | 18,848 |
| Asset retirement obligation | 13,670 |
| Other | 4,701 |
| | |
| Total current liabilities | 58,668 |
| | |
| Long-term debt | 264,000 |
| Asset retirement obligation | 77,483 |
| Fair value of derivatives | 8,876 |
| Other long-term liabilities | 38 |
| | |
| | |
| Total liabilities | 409,065 |
| Commitments and contingencies | |
| Unitholders' equity: | |
| Limited partners' equity - 40,067,701 units issued and | |
| outstanding at March 31, 2010 | 369,402 |
| General partner's equity | 47 |
| Total unitholders' equity | 369,449 |
| | |
| Total liabilities and unitholders' equity | $ 778,514 |
| |
| Selected Financial and Operating Data |
| |
| | Three Months Ended |
| | March 31, | December 31, | March 31, |
| | 2010 | 2009 | 2009 |
| | (In thousands, except per unit data) |
| Revenues: | | | |
| Oil sales | $ 37,748 | $ 33,613 | $ 16,465 |
| Natural gas liquid sales | 3,750 | 3,651 | 2,069 |
| Natural gas sales | 8,169 | 7,203 | 4,525 |
| | | | |
| Total revenue | $ 49,667 | $ 44,467 | $ 23,059 |
| | | | |
| Expenses: | | | |
| Oil and natural gas production | $ 14,156 | $ 11,638 | $ 10,537 |
| Ad valorem taxes | $ 914 | $ 1,189 | $ 1,465 |
| | | | |
| Total oil and natural gas production including ad valorem taxes | $ 15,070 | $ 12,827 | $ 12,002 |
| Production and other taxes | $ 2,919 | $ 2,654 | $ 1,353 |
| General and administrative | $ 4,761 | $ 4,233 | $ 3,368 |
| Depletion, depreciation, amortization and accretion | $ 13,115 | $ 15,291 | $ 16,621 |
| | | | |
| Realized commodity derivative settlements: | | | |
| Realized gain (loss) on oil swaps and collars | $ 2,907 | $ 3,938 | $ 14,912 |
| Realized gain (loss) on natural gas liquid swaps | $ (39) | $ (16) | $ 470 |
| Realized gain on natural gas swaps | $ 1,921 | $ 2,795 | $ 3,597 |
| | | | |
| Production: | | | |
| Oil - barrels | 504 | 461 | 460 |
| Natural gas liquids - gallons | 3,457 | 3,802 | 3,388 |
| Natural gas - Mcf | 1,216 | 1,242 | 1,249 |
| Total (MBoe) | 789 | 759 | 749 |
| Average daily production (Boe/d) | 8,767 | 8,250 | 8,322 |
| | | | |
| Average sales price per unit (excluding commodity derivatives): | | | |
| Oil price per barrel | $ 74.90 | $ 72.91 | $ 35.79 |
| Natural gas liquid price per gallon | $ 1.08 | $ 0.96 | $ 0.61 |
| Natural gas price per Mcf | $ 6.72 | $ 5.80 | $ 3.62 |
| Combined (per Boe) | $ 62.95 | $ 58.59 | $ 30.79 |
| | | | |
| Average sales price per unit (including realized commodity derivative settlements): | | | |
| Oil price per barrel | $ 80.66 | $ 81.46 | $ 68.21 |
| Natural gas liquid price per gallon | $ 1.07 | $ 0.96 | $ 0.75 |
| Natural gas price per Mcf | $ 8.30 | $ 8.05 | $ 6.50 |
| Combined (per Boe) | $ 69.02 | $ 67.44 | $ 56.13 |
| | | | |
| NYMEX oil index prices per barrel: | | | |
| Beginning of Period | $ 79.36 | $ 70.61 | $ 44.60 |
| End of Period | $ 83.76 | $ 79.36 | $ 49.66 |
| | | | |
| NYMEX gas index prices per Mcf: | | | |
| Beginning of Period | $ 5.57 | $ 4.84 | $ 5.62 |
| End of Period | $ 3.87 | $ 5.57 | $ 3.78 |
| | | | |
| Average unit costs per Boe: | | | |
| Oil and natural gas production | $ 17.94 | $ 15.33 | $ 14.07 |
| Ad valorem taxes | $ 1.16 | $ 1.57 | $ 1.96 |
| Production and other taxes | $ 3.70 | $ 3.50 | $ 1.81 |
| General and administrative | $ 6.03 | $ 5.58 | $ 4.50 |
| Depletion, depreciation, amortization and accretion | $ 16.62 | $ 20.15 | $ 22.19 |
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 related to LTIP unit awards accounted for under the equity or liability methods;
- Unrealized (gain) loss on oil and natural gas derivatives; and
- Equity in (income) loss of partnerships.
Distributable Cash Flow is defined as Adjusted EBITDA less:
- Cash interest expense;
- Cash income taxes;
- Cash settlements of unit awards; and
- Development capital expenditures.
Adjusted EBITDA and Distributable Cash Flow are presented as management believes they provide additional information and metrics relative to the performance of our business, such as the cash distributions we expect to pay to our unitholders, as well as our ability to meet our debt covenant compliance tests. Management believes that these financial measures indicate to investors whether or not cash flow is being generated at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA and Distributable Cash Flow may not be comparable to a similarly titled measure of other publicly traded limited partnerships or limited liability companies because all companies may not calculate Adjusted EBITDA in the same manner.
The following table presents a reconciliation of our consolidated net income (loss) to Adjusted EBITDA and Distributable Cash Flow:
| | Three Months Ended |
| | March 31, | December 31, | March 31, |
| | 2010 | 2009 | 2009 |
| | (dollars in thousands) |
| Net income (loss) | $ 10,220 | $ (38,477) | $ 3,489 |
| Plus: | | | |
| Interest expense | 7,333 | 2,112 | 4,259 |
| Income taxes | 173 | 148 | 111 |
| Depletion, depreciation, amortization and accretion | 13,115 | 15,291 | 16,621 |
| Impairment of long-lived assets | 7,916 | 5,224 | 1,156 |
| Gain on disposal of assets | -- | 12 | (60) |
| Equity in income of partnership | (23) | (17) | 2 |
| Unit-based compensation expense | 1,022 | 1,004 | (281) |
| Unrealized (gain) loss on oil and natural gas derivatives | (7,072) | 47,058 | (526) |
| Adjusted EBITDA | $ 32,684 | $ 32,355 | $ 24,771 |
| | | | |
| Less: | | | |
| Cash interest expense | 3,703 | 3,707 | 4,955 |
| LTIP settlements | 1,702 | 113 | 176 |
| Development capital expenditures | 5,202 | 3,332 | 4,769 |
| Distributable Cash Flow | $ 22,077 | $ 25,203 | $ 14,871 |
CONTACT: Legacy Reserves LP
Steven H. Pruett, President and Chief Financial Officer
432-689-5200