Legacy Reserves LP Announces Second Quarter 2015 Results

MIDLAND, Texas, Aug. 5, 2015 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (NASDAQ:LGCY) today announced second quarter results for 2015.

Q2 highlights include:

• Production of 33,571 Boe/d
   
• Lease operating expense (excluding ad valorem taxes) of $42.8 million, a $3.1 million (6.8%) improvement relative to Q1 2015 and a $10.4 million (19.5%) improvement relative to Q4 2014
   
• Adjusted EBITDA of $69.9 million, an $8.0 million (12.8%) improvement relative to Q1 2015 on a net loss of approximately $38.5 million
   
• Distributable Cash Flow of $39.8 million, a $13.0 million (48.5%) improvement relative to Q1 2015, covering our quarterly distribution by 1.64 times

Paul T. Horne, President and Chief Executive Officer of Legacy commented, "The Legacy team did an outstanding job in Q2. By all accounts, our folks delivered their numbers. We realized an approximate 7% decline in LOE relative to Q1 and 20% relative to Q4 2014, all while holding production relatively flat over that period. As a company we are excelling in nearly all areas we control and for that I am extremely proud. We remain excited about our recently-announced East Texas acquisitions, which closed on July 31. We are currently integrating those assets and building our team to take on those assets. We are also excited to have spudded the first well under our Joint Development Agreement with TPG Special Situations Partners and are bringing in our second and third rigs for those operations in the coming days. In spite of our great execution, we are cognizant of the incredibly challenging market environment. We will continue to watch commodity prices and, given our lack of meaningful operational commitments, can remain flexible to respond as needed in the future. We remain focused on creating value for our unitholders and positioning ourselves for the future."

Dan Westcott, Executive Vice President and Chief Financial Officer of Legacy commented, "I am really pleased with our Q2 results. Our team is giving their all and it shows throughout our financials. In addition to the lower costs and flat production, we posted record quarterly distribution coverage of 1.64 times. Regarding our balance sheet, in conjunction with our East Texas acquisitions, our bank group increased our borrowing base from $700 million to $950 million. Today we have approximately $400 million of availability under our revolver which we believe leaves us ample room for our business. Our banks have been valuable partners throughout our history and we appreciate their continued efforts and support. We have already added hedges to cover the production from the East Texas assets and will continue to monitor commodity futures prices to add additional hedges as warranted. In spite of the drop in commodity prices, we expect to achieve our 1.3 times 2015 distribution coverage goal stated earlier this year with the second half averaging nearly 1.2 times. Our $850 million of long-term capital raised in 2014 will prove helpful in this difficult environment as we continue to try to balance prudent protection with pragmatic progress."

Financial and Operating Results - Second Quarter 2015 Compared to Second Quarter 2014

• Production increased 44% to 33,571 Boe/d from 23,286 Boe/d primarily due to our 2014 acquisitions including our Piceance Basin acquisition from WPX Energy, Inc. ("WPX Acquisition").
   
• Average realized price, excluding net cash settlements from commodity derivatives, decreased 56% to $28.74 per Boe in 2015 from $64.71 per Boe in 2014 driven by the significant decline in commodity prices as well as the increase of NGL and natural gas production as a percentage of total production. Average realized oil price decreased 45% to $50.48 in 2015 from $92.54 in 2014 driven by a decrease in the average West Texas Intermediate ("WTI") crude oil price of $45.40 per Bbl partially offset by a decrease in realized regional differentials. Average realized natural gas price decreased 50% to $2.38 per Mcf in 2015 from $4.77 per Mcf in 2014. This decrease is a result of the decrease in the average Henry Hub natural gas index price of approximately $1.94 per Mcf as well as the inclusion of lower priced natural gas production from the WPX Acquisition. Finally, our average realized NGL price decreased 46% to $0.50 per gallon in 2015 from $0.92 per gallon in 2014. This decrease is due to the combination of lower commodity prices and the inclusion of lower priced NGL production from the WPX Acquisition.
   
• Production expenses, excluding ad valorem taxes, increased 2% to $42.8 million in 2015 from $42.1 million in 2014. On an average cost per Boe basis, production expenses decreased 29% to $14.02 per Boe in 2015 from $19.85 per Boe in 2014, driven primarily by expense reduction efforts across the properties that we have owned prior to the WPX Acquisition as well as the inclusion of lower cost natural gas properties acquired in the WPX Acquisition.
   
• General and administrative expenses, excluding unit-based Long-Term Incentive Plan ("LTIP") compensation expense totaled $8.2 million in 2015 compared to $12.7 million in 2014. This decrease was primarily due to a $3.2 million decrease in acquisition costs between the periods as we incurred approximately $4.8 million of one-time acquisition-related expenses during Q2 2014 associated with the WPX Acquisition and the remainder attributable to overall general and administrative expense reduction efforts.
   
• Cash settlements received on our commodity derivatives during 2015 were $37.2 million compared to cash settlements paid of approximately $6.0 million in 2014.
   
• Total development capital expenditures decreased to $8.4 million in 2015 from $36.1 million in 2014. The 2015 activity was comprised mainly of the drilling and completion of a non-operated horizontal Bone Springs well, completion costs on an operated horizontal Bone Springs well and capital costs related to CO₂ properties. Our non-operated capital expenditures were 51% of total capital for the quarter compared to 14% in 2014.

Financial and Operating Results - Second Quarter Year to Date 2015 Compared to Second Quarter Year to Date 2014

• Production increased 57% to 33,674 Boe/d from 21,392 Boe/d primarily due to acquisitions in 2014 including the WPX Acquisition.
   
• Average realized price, excluding net cash settlements from commodity derivatives, decreased 59% to $27.78 per Boe in 2015 from $67.93 per Boe in 2014 driven by the significant decline in commodity prices as well as the increase in NGL and natural gas production as a percentage of total production. Average realized oil price decreased 49% to $46.14 in 2015 from $91.25 in 2014 driven by a decrease in the average WTI crude oil price of $47.71 per Bbl partially offset by a decrease in realized regional differentials. Average realized natural gas price decreased 51% to $2.59 per Mcf in 2015 from $5.33 per Mcf in 2014. This decrease is a result of the decrease in the average Henry Hub natural gas index price of approximately $2.04 per Mcf as well as the inclusion of lower priced natural gas production from the WPX Acquisition. Finally, our average realized NGL price decreased 54% to $0.47 per gallon in 2015 from $1.02 per gallon in 2014. This decrease is due to the combination of lower commodity prices and the inclusion of lower priced NGL production from the WPX Acquisition.
   
• Production expenses, excluding ad valorem taxes, increased 9% to $88.8 million in 2015 from $81.7 million in 2014. On an average cost per Boe basis, production expenses decreased 31% to $14.56 per Boe in 2015 from $21.10 per Boe in 2014, driven primarily by expense reduction efforts across the properties that we have owned prior to the WPX Acquisition as well as the inclusion of lower cost natural gas properties acquired in the WPX Acquisition.
   
• Non-cash impairment expense totaled $209.4 million driven by the significant decline in natural gas futures prices during the first quarter of 2015.
   
• General and administrative expenses, excluding unit-based LTIP compensation expense totaled $16.0 million in 2015 compared to $19.6 million in 2014. This decrease was primarily due to a $3.2 million decrease in acquisition costs between the periods as we incurred approximately $4.8 million of one-time acquisition-related expenses during Q2 2014 associated with the WPX Acquisition and the remainder attributable to overall general and administrative expense reduction efforts.
   
• Cash settlements received on our commodity derivatives during 2015 were $77.5 million compared to cash settlements paid of approximately $9.6 million in 2014.
   
• Total development capital expenditures decreased to $21.8 million in 2015 from $57.9 million in 2014. The 2015 activity was comprised mainly of the drilling and completion of two horizontal Wolfcamp wells, completion costs on an operated horizontal Bone Springs well, drilling and completion costs on a non-operated horizontal Bone Springs well and capital costs related to CO₂ properties. Our non-operated capital expenditures were 20% of total capital for the quarter compared to 23% in 2014.

Commodity Derivative Contracts

We enter into oil and natural gas derivative contracts to help mitigate the risk of changing commodity prices. As of August 5, 2015, we had entered into derivative agreements to receive average NYMEX WTI crude oil prices and NYMEX Henry Hub, Waha, NWPL, NGPA, SoCal, San Juan and CIG-Rockies natural gas prices as summarized below:

WTI Crude Oil Swaps:

WTI Crude Oil 3-Way Collars:

WTI Crude Oil Enhanced Swaps:

Midland-to-Cushing WTI Crude Oil Differential Swaps:

Natural Gas Swaps (Henry Hub, Waha and CIG-Rockies):

Natural Gas 3-Way Collars (Henry Hub):

Natural Gas Basis Swaps (NWPL, NGPA, SoCal, San Juan and Waha):

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.

Quarterly Report on Form 10-Q

Financial results contained herein are preliminary and subject to the final, unaudited financial statements and related footnotes included in Legacy's Form 10-Q which will be filed on or about August 7, 2015.

Conference Call

As announced on July 21, 2015, Legacy will host an investor conference call to discuss Legacy's results on Thursday, August 6, 2015 at 9:00 a.m. (Central Time). Those wishing to participate in the conference call should dial 877-266-0479. A replay of the call will be available through Thursday, August 13, 2015, by dialing 855-859-2056 or 404-537-3406 and entering replay code 87656715. Those wishing to listen to the live or archived web cast via the Internet should go to the Investor Relations tab of our website at www.LegacyLP.com. Following our prepared remarks, we will be pleased to answer 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 a master limited partnership headquartered in Midland, Texas, focused on the acquisition and development of oil and natural gas properties primarily located in the Permian Basin, East Texas, Rocky Mountain 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 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.

Adjusted EBITDA and Distributable Cash Flow are presented as management believes they provide additional information concerning the performance of our business and are used by investors and financial analysts to analyze and compare our current operating and financial performance relative to past performance and such performances relative to that of other publicly traded partnerships in the industry. Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other publicly traded limited partnerships or limited liability companies because all companies may not calculate such measures in the same manner.

Distributable Cash Flow is one of the factors used by the board of directors of our general partner (the "Board") to help determine the amount of Available Cash as defined in our partnership agreement, that is to be distributed to our unitholders for such period. Under our partnership agreement, Available Cash is defined generally to mean, cash on hand at the end of each quarter, plus working capital borrowings made after the end of the quarter, less cash reserves determined by our general partner. The Board determines whether to increase, maintain or decrease the current level of distributions in accordance with the provisions of our partnership agreement based on a variety of factors, including without limitation, Distributable Cash Flow, cash reserves established in prior periods, reserves established for future periods, borrowing capacity for working capital, temporary, one-time or uncharacteristic historical results, and forecasts of future period results including the impact of pending acquisitions. Management and the Board consider the long-term view of expected results in determining the amount of its distributions. Certain factors impacting Adjusted EBITDA and Distributable Cash Flow may be viewed as temporary, one-time in nature, or being offset by reserves from past performance or near-term future performance. Financial results are also driven by various factors that do not typically occur evenly throughout the year that are difficult to predict, including rig availability, weather, well performance, the timing of drilling and completions and near-term commodity price changes. Consistent with practices common to publicly traded partnerships, the Board historically has not varied the distribution it declares based on such timing effects.

"Adjusted EBITDA" and "Distributable Cash Flow" should not be considered as alternatives to GAAP measures, such as net income, operating income, cash flow from operating activities, or any other GAAP measure of financial performance.

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