updated 11/3/2010 6:46:37 PM ET 2010-11-03T22:46:37

MIDLAND, Texas, Nov. 3, 2010 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced third quarter results for 2010. The final unaudited Quarterly Report will be released on or about November 5, 2010.

A summary of selected financial information follows. For consolidated financial statements, please see accompanying tables.

Highlights of the third quarter of 2010 compared to the second quarter of 2010:

  • Production increased 3% to 9,804 Boe per day in the third quarter from 9,516 Boe per day in the second quarter due to production from recent acquisitions, operational improvements and increased development drilling. These increases in production were partially offset by a decrease in production due to gathering system and processing plant downtime from one of our gas purchasers in the Texas Panhandle.
  • Oil, natural gas liquids ("NGL") and natural gas sales, excluding commodity derivatives settlements, were $52.8 million in the third quarter, up 2% from $51.6 million in the second quarter, as increased production was partially offset by lower realized commodity prices.
  • Average realized prices, excluding commodity derivatives settlements, were $58.51 per Boe in the third quarter, down 2% from $59.62 per Boe in the second quarter. Average realized oil prices declined 2% to $70.21 per Bbl in the third quarter from $71.78 per Bbl in the second quarter, and average realized NGL prices declined 9% to $0.96 per gallon in the third quarter from $1.06 per gallon in the second quarter. These declines were partially offset by a 3% increase in average realized natural gas prices to $5.40 per Mcf in the third quarter from $5.26 per Mcf in the second quarter.    
  • Production expenses, excluding taxes, decreased 7% to $14.9 million in the third quarter from $16.0 million in the second quarter. On an average unit cost per Boe, production expenses declined 10% to $16.53 per Boe in the third quarter from $18.44 per Boe in the second quarter. In the second quarter, production expenses included $1.5 million of expenses related to improving or re-establishing production on select properties in our $125 million Wyoming acquisition, which closed on February 17, 2010. The absence of such expenses in the third quarter was partially offset by additional production expenses associated with more recent acquisitions.
  • General and administrative costs increased to $4.5 million, or $5.03 per Boe, in the third quarter from $4.0 million, or $4.67 per Boe, in the second quarter of 2010 due primarily to increased non-cash compensation expense. Non-cash compensation expense related to the partnership's long-term incentive plan ("LTIP") was $1.3 million in the third quarter ($1.45 per Boe) compared to $1.0 million ($1.10 per Boe) in the second quarter, as a significant mark-to-market adjustment in Legacy's LTIP liability caused by the increase in the price of Legacy's partnership units resulted in increased non-cash compensation expense. Cash settlements on our LTIP dropped to $0.1 million ($0.15 per Boe) in the third quarter from $0.2 million ($0.24 per Boe) in the second quarter. While LTIP cash settlements do not affect reported general and administrative costs, these settlements reduce distributable cash flow.
  • Cash settlements received on our commodity derivatives during the third quarter were $6.3 million compared to $4.2 million received during the second quarter, with the increase primarily attributable to lower realized commodity prices during the third quarter as well as a favorable crude oil hedge contract that started at the beginning of the third quarter. Our production was 76% hedged in the third quarter compared to 73% in the second quarter. We reported an unrealized loss of $26.2 million on our commodity derivatives portfolio in the third quarter compared to an unrealized gain of $34.1 million in the second quarter. The significant unrealized loss in the third quarter was caused by increases in NYMEX crude oil futures prices.
  • Adjusted EBITDA increased 11% to $35.7 million during the third quarter from $32.3 million in the second quarter, as higher production volumes, lower production expenses and higher cash settlements on commodity derivatives were only partially offset by lower realized commodity prices and higher general and administrative costs, excluding non-cash compensation expense. (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 $9.0 million in the third quarter from $5.1 million in the second quarter. Oilfield service delays in both rigs and fracture stimulation crews during the first half of 2010 caused our capital expenditures budget to be heavily weighted toward the second half of 2010. Given our $31 million development capital expenditures budget for 2010 and our actual development capital expenditures of approximately $19.3 million through the first three quarters of this year, we are planning on development capital expenditures of approximately $11.7 million during the fourth quarter of 2010, although the timing of these expenditures, particularly costs associated with the drilling of non-operated wells, is uncertain.
  • Distributable cash flow decreased in the third quarter to $22.2 million from $23.3 million in the second quarter, as increased Adjusted EBITDA was more than offset by increased development capital expenditures during the third quarter.
  • Distributable cash flow per unit decreased to $0.55 per unit in the third quarter from $0.58 per unit in the second quarter due to increased development capital expenditures during the third quarter. We paid a distribution of $0.52 per unit on 40,162,479 units on August 13, 2010.
  • Our net loss of $20.2 million, or $0.50 per unit, in the third quarter of 2010 was unfavorably impacted by $26.2 million of unrealized losses on our commodity derivatives and a $4.2 million impairment charge on our oil and natural gas properties.  We generated net income of $39.4 million, or $0.98 per unit, in the second quarter of 2010, which included $34.1 million of unrealized gains on our commodity derivatives and a $0.5 million impairment charge on our oil and natural gas properties.

Cary D. Brown, Chairman and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, commented:  "Legacy's third quarter results were very encouraging. Despite a slight decline in commodity prices, we realized 11% growth in EBITDA during the third quarter due to increased production, lower production expenses and higher cash settlements on our commodity derivatives. Although we continued to experience gathering and processing issues in the Texas Panhandle, we increased production in the third quarter to 9,804 Boe per day from 9,516 Boe per day in the second quarter. These increases were due to bolt-on acquisitions in the Permian Basin and Wyoming, operational improvements on our Wyoming and other base properties, and increased development drilling. From July 1 through October 4, we closed an additional 8 transactions for approximately $16.3 million, bringing us to a total of 20 transactions for approximately $173 million during 2010. Our current backlog of potential acquisitions is sizable, and we feel confident about our ability to grow through acquisitions. In addition, we continue to be encouraged by the results of our development drilling and recompletion projects, which are meeting or exceeding our expectations. Finally, we are pleased to report that during the third quarter, even after we deducted $9 million of development capital expenditures, we still generated $22.2 million or $0.55 per unit of distributable cash flow, covering our $0.52 distribution by 1.06 times. We maintained positive momentum during the third quarter, and look forward to continued growth in the fourth quarter as well as 2011." 

Steven H. Pruett, President and Chief Financial Officer, commented, "As reported in an earlier press release, our lenders redetermined and maintained our $410 million borrowing base on our $600 million credit facility in early October. As of November 3, we have approximately $120 million of borrowing capacity under this agreement. With strong public capital markets and a favorable lending environment, we are confident in our ability to finance potential acquisitions."

New Commodity Derivatives Contracts

On October 6, 2010, Legacy entered into crude oil derivatives contracts with four counterparties, all of which are lenders to Legacy under its credit agreement. These contracts are summarized as follows:

(a) As part of an oil swap transaction entered into with a counterparty, we sold two call options to the counterparty that allow the counterparty to extend this swap transaction covering calendar year 2011 to either 2012, 2013 or both calendar years. The counterparty must exercise or decline the option covering calendar year 2012 on December 30, 2011 and the option covering calendar year 2013 on December 31, 2012. If exercised, we would pay the counterparty floating prices and receive a fixed price of $98.25 on annual notional volumes of 183,000 Bbls in 2012 and 182,500 Bbls in 2013. The premium paid by the counterparty for the two call options was received by us as an increase in the fixed price that we will receive pursuant to the 2011 swap of $98.25 per Bbl on 182,500 Bbls, or 500 Bbls per day, rather than the prevailing market price of approximately $87.00 per Bbl.

Commodity Derivatives Contracts

We have entered into the following oil and natural gas derivatives contracts, including swaps, collars and three-way collars, to help mitigate the risk of changing commodity prices. As of November 3, 2010, we had entered into derivatives 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 October 2010 through December 2015:


On May 3, 2010, we entered into two separate NYMEX West Texas Intermediate crude oil derivative three-way collar contracts. On October 6, 2010, we entered into eight additional NYMEX West Texas Intermediate crude oil derivative three-way collar contracts. Each contract combines a long put, a short put and 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 November 3, 2010, through December 31, 2015:

Additionally, we have entered into a costless collar for NYMEX WTI with the following attributes:

Natural Gas:

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:

Quarterly Report on Form 10-Q

The consolidated financial statements and related footnotes will be available in our September 30, 2010 Form 10-Q, which will be filed on or about November 5, 2010.

Conference Call

As announced on October 21, 2010, Legacy will host an investor conference call to discuss Legacy's results on Thursday, November 4, 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, November 8, 2010, by dialing 706-645-9291 or 800-642-1687 and entering replay code  19453244, 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, 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.

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 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.  

"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 partnership.

Distributable Cash Flow is defined as Adjusted EBITDA less:

  • Cash interest expense;
  • Cash income taxes;
  • Cash settlements of LTIP unit awards; and
  • Development capital expenditures.

The following table presents a reconciliation of our consolidated net income (loss) to Adjusted EBITDA and Distributable Cash Flow:

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