Legacy Reserves LP Announces Fourth Quarter and Annual 2014 Results, 2015 Guidance and New Chief Operating Officer

MIDLAND, Texas, Feb. 25, 2015 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced fourth quarter and annual results for 2014 as well as financial guidance for 2015. Financial results contained herein are preliminary and subject to the audited financial statements included in Legacy's Form 10-K to be filed on or about February 27, 2015.

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

2014 highlights include:

• Generated record annual production of 26,962 Boe/d up 37% from 19,668 Boe/d in 2013
• Generated record annual EBITDA of $278.2 million
• Completed $536.3 million of acquisitions including our $360.0 million acquisition of natural gas properties located in the Piceance Basin from WPX Energy, Inc.
• Year-end proved reserves increased 59% to a record 139.0 MMBoe (90% PDP, 50% liquids)

Management Transition

Cary D. Brown, Chairman, President and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, stated: "As previously released, this is my last week as CEO. I look forward to serving the company as I transition my role to Chairman. While we and our industry face an uphill battle given current commodity prices, I am extremely comforted by the team we have put in place to navigate these difficult waters. With our long-lived, low-decline assets, solid hedges, and ample liquidity under our revolver, we are well positioned for the future."

Paul T. Horne, currently Executive Vice President and Chief Operating Officer and soon-to-be President and Chief Executive Officer, commented, "First off, I'd like to thank Cary for all he has done in building and leading Legacy. I'm grateful for the opportunity that he and the Board have provided me and I look forward to leading the organization forward. We accomplished a great deal in 2014 and I would like to thank our employees for their hard work. We acquired over $530 million of properties this year including our strategic alliance with WPX. We posted record production and EBITDA and we raised a tremendous amount of long-term focused capital. All of these accomplishments put us in a better position today and for that I'm thankful.

"We undoubtedly face challenging commodity prices. While it's not fun, we've been here several times before, and we know what to do in this environment. We are reigning in costs across the board and we have dramatically reduced our capital budget, from $133 million in 2014 to $30 million in 2015. We expect service costs to fall commensurate with price and will continue to evaluate our capital budget options throughout the year.

Legacy is also pleased to announce the appointment of Kyle M. Hammond as Executive Vice President and Chief Operating Officer of Legacy Reserves GP, LLC effective March 1, 2015. Prior to joining Legacy, Mr. Hammond founded and served as President and Chief Executive Officer of FireWheel Energy LLC ("FireWheel") since August 2011. Prior to forming FireWheel, Mr. Hammond served as VP of Operations for the Permian Division of  XTO Energy/Exxon from 2003 to August 2011. While there, Mr. Hammond managed the growth of the Permian assets as well as their Alaskan operations. Mr. Hammond earned a BS in Petroleum Engineering from Texas A&M University. Mr. Hammond currently serves on the board of directors of Abilene Christian University and Midland Christian School.

Mr. Horne added, "I am thrilled to have Kyle Hammond join the team. I've known Kyle since our time together at Texas A&M and respect the person, oilman, and Aggie engineer that he is. The operational, management and growth experience he gained at XTO will help us immensely at Legacy."

Credit Agreement Update

On February 23, 2015, Legacy amended the terms of its Credit Agreement. Principle modifications include the replacement of the Total Debt / EBITDA covenant with a maximum 2.5x Secured Debt / EBITDA covenant and a minimum 2.5x EBITDA / Interest covenant. The Partnership's year-end statistics for these two covenants were 0.4x and 4.1x. Legacy also agreed to reduce its borrowing base to $700 million from the prior $950 million. As of February 23, 2015, Legacy had approximately $130 million of borrowings outstanding, providing approximately $570 million of liquidity available.

Dan Westcott, Executive Vice President and Chief Financial Officer, commented, "I'd like to say thank you to Wells Fargo and the rest of our 19-member bank group for their diligence and support in helping us get this amendment executed. With our new financial covenants, we have meaningfully increased our effective liquidity and have greater capacity to swiftly make accretive acquisitions in this market."

Proved Reserves

Our proved reserves by operating region as of December 31, 2014 are as follows:

2015 Guidance

The following table sets forth certain assumptions used by Legacy to estimate its anticipated results of operations for 2015. These estimates do not include any acquisitions of additional oil or natural gas properties. In addition, these estimates are based on, among other things, assumptions of capital expenditure levels, current indications of supply and demand for oil and natural gas and current operating and labor costs. The guidance set forth below does not constitute any form of guarantee, assurance or promise that the matters indicated will actually be achieved. The guidance below sets forth management's best estimate based on current and anticipated market conditions and other factors. While we believe that these estimates and assumptions are reasonable, they are inherently uncertain and are subject to, among other things, significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate, as set forth under "Cautionary Statement Relevant to Forward-Looking Information."

Annual Financial and Operating Results - 2014 Compared to 2013

• Production increased 37% to an annual record of 26,962 Boe/d from 19,668 Boe/d primarily due to $536.3 million of acquisitions in 2014 including our $360.0 million acquisition of non-operated interest in oil and natural gas properties located in the Piceance Basin in Garfield County, Colorado from WPX Energy, Inc ("WPX Acquisition"). Additionally, production was positively impacted by our record $133.4 million of development capital expenditures during 2014.
   
• Average realized price, excluding net cash settlements from commodity derivatives, decreased 20% to $54.09 per Boe in 2014 from $67.63 per Boe in 2013. This decrease in realized prices was primarily driven by the increase of NGL and natural gas production as a percentage of total production. For instance, in 2014 NGLs and natural gas accounted for approximately 51% of our total production compared to approximately 38% in 2013. This increase in lower priced production reduced our total price realization. Average realized oil price decreased 8% to $82.94 in 2014 from $90.62 in 2013. This decrease was primarily driven by a decrease in the average West Texas Intermediate ("WTI") crude oil price of $5.07 per Bbl as well as an increase in realized differentials, primarily in the Permian Basin. Average natural gas price decreased 9% to $4.17 per Mcf in 2014 from $4.60 per Mcf in 2013. While the average Henry Hub natural gas index price increased $0.60 per Mcf, this increase was more than offset by the inclusion of approximately 11,767 MMcf of lower priced natural gas production from the WPX Acquisition. Finally, our average realized NGL price decreased 16% to $0.89 per gallon in 2014 from $1.06 per gallon in 2013. This decrease is due to the inclusion of lower priced NGL production from the WPX Acquisition. The large majority of our separately reported NGL production is from the properties acquired in the WPX Acquisition and our Mid-Continent region.
   
• Production expenses, excluding ad valorem taxes, increased 31% to $186.8 million in 2014 from $142.8 million in 2013. On an average cost per Boe basis, production expenses decreased 5% to $18.98 per Boe in 2014 from $19.89 per Boe in 2013, driven primarily by the inclusion of lower cost natural gas properties acquired in the WPX Acquisition.
   
• Non-cash impairment expense totaled $448.7 million driven by the significant decline in oil and natural gas prices during the fourth quarter of 2014.
   
• General and administrative expenses, excluding unit-based Long-Term Incentive Plan ("LTIP") compensation expense totaled $35.2 million in 2014 compared to $24.1 million in 2013. This increase was primarily due to $4.5 million of increased acquisition-related expenses and a $3.4 million increase in salary and benefit expenses.
   
• Cash settlements received on our commodity derivatives during 2014 were $2.7 million, as the $8.1 million received on our natural gas hedges was partially offset by $5.4 million paid on our crude oil hedges. Comparably, in 2013 we paid cash settlements on our commodity derivatives of approximately $7.1 million.
   
• Total development capital expenditures increased to $133.4 million in 2014 from $94.0 million in 2013, as we continued our one-rig Wolfberry program throughout 2014, drilled four horizontal Bone Spring wells, incurred capital costs related to our CO2 injection on properties acquired during 2014 and increased our other operated and non-operated drilling and capital workover activities, most of which were in the Permian Basin. Our non-operated capital expenditures were 28% of our total capital expenditures in 2014 as compared to 27% in 2013.

Financial and Operating Results - Fourth Quarter 2014 Compared to Fourth Quarter 2013

• Production increased 69% to 32,772 Boe/d from 19,402 Boe/d primarily due to the WPX Acquisition and other recent acquisitions.
   
• Average realized price, excluding net cash settlements from commodity derivatives, decreased 42% to $39.67 per Boe in 2014 from $68.37 per Boe in 2013 due to the significant increase in natural gas and NGL production as such products are generally less valuable per Boe than oil. Average realized oil price decreased 28% to $64.18 per Bbl in 2014 from $89.24 per Bbl in 2013. This decrease of $25.06 was primarily attributable to the sharp decline in the average WTI crude oil price of $24.30 combined with slightly higher realized regional differentials. Average realized natural gas prices declined 31% to $3.49 per Mcf in 2014 from $5.03 per Mcf in 2013. While the average Henry Hub natural gas price index increased by $0.23 per Mcf in 2014, this increase was more than offset by lower realized natural gas prices from natural gas production associated with the properties acquired in the WPX Acquisition. Finally, our average realized NGL price decreased 36% to $0.71 per gallon in 2014 from $1.11 per gallon in 2013 which was attributable to the lower priced production from the WPX Acquisition.
   
• Production expenses, excluding ad valorem taxes, increased 35% to $53.2 million in 2014 from $39.5 million in 2013. Production expenses increased primarily due to expenses associated with our acquisitions, including $11.0 million related to the WPX Acquisition and, to a lesser extent, industry-wide cost increases. On a per Boe basis, production expenses decreased from $22.12 to $17.65 or 20% driven by acquisitions of properties with lower per Boe production expenses as well as cost reductions in our ongoing operations.
   
• Non-cash impairment expense totaled $440.1 million due to the significant decline of oil and natural gas prices during the period.
   
• General and administrative expenses, excluding LTIP compensation expense, increased to $8.3 million in 2014 from $6.4 million in 2013. This increase was primarily attributable to an increase in salary and benefit expenses related to the hiring of additional personnel to manage our larger asset base.
   
• Cash settlements received on our commodity derivatives were $14.6 million during 2014 compared to cash settlements paid of $2.4 million in 2013, a reflection of the sharp decline in commodity prices during the fourth quarter of 2014. Additionally, as our crude oil derivatives settle one-month in arrears, we incurred a hedge-lag effect of approximately $10.5 million.
   
• Total development capital expenditures were $42.0 million in the fourth quarter of 2014. Non-operated capital expenditures comprised 39% of our total capital expenditures during the period with activity primarily in the Permian.

Commodity Derivative Contracts

We enter into oil and natural gas derivative contracts to help mitigate the risk of changing commodity prices. As of February 25, 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.

Annual Report on Form 10-K

Our consolidated, audited financial statements and related footnotes will be available in our annual 2014 Form 10-K which will be filed on or about February 27, 2015.

Conference Call

As announced on January 23, 2015, Legacy will host an investor conference call to discuss Legacy's results on Thursday, February 26, 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, March 5, 2015, by dialing 855-859-2056 or 404-537-3406 and entering replay code 70464452. 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, 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.

Adjusted EBITDA is defined 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;
• Equity in (income) loss of equity method investees;
• Unit-based compensation expense (benefit) related to LTIP unit awards accounted for under the equity or liability methods;
• Minimum payments received in excess of overriding royalty interest earned;
• Equity in EBITDA of equity method investee;
• Net (gains) losses on commodity derivatives;
• Net cash settlements received (paid) on commodity derivatives; and
• Transaction expenses related to acquisitions.

Distributable Cash Flow is defined as Adjusted EBITDA less:

• Cash interest expense including the accrual of interest expense related to our senior notes which is paid on a semi-annual basis;
• Cash income taxes;
• Cash settlements of LTIP unit awards;
• Estimated maintenance capital expenditures; and
• Distributions on Series A and Series B preferred units.

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