May 3, 2017

Legacy Reserves LP Announces First Quarter 2017 Results and Provides Operational and Financial Update

MIDLAND, Texas, May 03, 2017 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (NASDAQ:LGCY) today announced first quarter results for 2017 including the following Q1 highlights:

  • Deployed $23.7 million of development capital as follows:
    - $16.7 million on drilling 8 and completing 7 Permian horizontal wells in Howard County, TX and Lea County, NM under our Joint Development Agreement ("JDA")
    - $4.1 million on workovers across all operating regions
    - $1.5 million on infrastructure and CO2
    - $1.4 million on non-operated properties

  • Spent approximately $4.8 million acquiring additional Midland Basin leasehold adding 24 gross potential horizontal drilling locations.

  • Generated net income of $16.4 million.

  • Obtained the reaffirmation of a $600 million borrowing base under our revolving credit facility.

Paul T. Horne, Chairman, President and Chief Executive Officer, commented, "Our company started the year off well as we grew oil production by 9% relative to Q4 of last year, driven by our recent Permian horizontal drilling efforts. While LOE was up 19% relative to Q4, the primary driver was an increase in returning wells to production and workovers that are now economic in an improved commodity price environment. This proactive well work in the Permian Basin and East Texas served to further reduce oil and gas declines for our portfolio of shallow-decline properties, the base from which we intend to grow the business in 2017 and beyond."

Dan Westcott, Executive Vice President and Chief Financial Officer, commented, "We are extremely proud of our team's execution of the Permian horizontal development that we outlined at year-end. Our front-end weighted capital program is concentrated on high-return projects and we anticipate continued oil production growth throughout the year. During the quarter, we again improved our credit profile as we reduced our borrowings outstanding by $15 million and maintained our $600 million borrowing base. We remain focused on the prudent management of our shallow-decline properties and the efficient development of our horizontal Permian potential."


 Three Months Ended
March 31,
 2017 2016
 (In thousands, except
per unit data)
Oil sales$49,142  $30,320 
Natural gas liquids (NGL) sales5,050  2,453 
Natural gas sales45,355  33,086 
Total revenue$99,547  $65,859 
Oil and natural gas production, excluding ad valorem taxes$49,228  $46,661 
Ad valorem taxes$1,989  $3,362 
Total oil and natural gas production$51,217  $50,023 
Production and other taxes$4,159  $2,573 
General and administrative, excluding trans. related costs and LTIP  $8,623  $7,692 
Transaction related costs$32  $77 
LTIP expense$1,897  $1,665 
Total general and administrative$10,552  $9,434 
Depletion, depreciation, amortization and accretion$28,796  $36,959 
Commodity derivative cash settlements:   
Oil derivative cash settlements received$3,139  $12,585 
Natural gas derivative cash settlements received$1,097  $10,192 
Oil (MBbls)1,037  1,069 
Natural gas liquids (MGal)7,653  8,241 
Natural gas (MMcf)15,592  17,266 
Total (MBoe)3,818  4,143 
Average daily production (Boe/d)42,422  45,527 
Average sales price per unit (excluding derivative cash settlements):   
Oil price (per Bbl)$47.39  $28.36 
Natural gas liquids price (per Gal)$0.66  $0.30 
Natural gas price (per Mcf)$2.91  $1.92 
Combined (per Boe)$26.07  $15.90 
Average sales price per unit (including derivative cash settlements):   
Oil price (per Bbl)$50.42  $40.14 
Natural gas liquids price (per Gal)$0.66  $0.30 
Natural gas price (per Mcf)$2.98  $2.51 
Combined (per Boe)$27.18  $21.39 
Average WTI oil spot price (per Bbl)$51.62  $33.35 
Average Henry Hub natural gas index price (per MMbtu)$3.02  $1.99 
Average unit costs per Boe:   
Oil and natural gas production, excluding ad valorem taxes$12.89  $11.26 
Ad valorem taxes$0.52  $0.81 
Production and other taxes$1.09  $0.62 
General and administrative excluding trans. related costs and LTIP$2.26  $1.86 
Total general and administrative$2.76  $2.28 
Depletion, depreciation, amortization and accretion$7.54  $8.92 

Financial and Operating Results - Three-Month Period Ended March 31, 2017 Compared to Three-Month Period Ended March 31, 2016

  • Production decreased 7% to 42,422 Boe/d from 45,527 Boe/d primarily due to natural production declines and immaterial divestitures completed in 2016. This decline was partially offset by additional production from our drilling operations in Howard County, Texas and Lea County, New Mexico.

  • Average realized price, excluding net cash settlements from commodity derivatives, increased 64% to $26.07 per Boe in 2017 from $15.90 per Boe in 2016 driven by the significant increase in commodity prices. Average realized oil price increased 67% to $47.39 in 2017 from $28.36 in 2016 driven by an increase in the average West Texas Intermediate ("WTI") crude oil price of $18.27 per Bbl and improving regional differentials. Average realized natural gas price increased 52% to $2.91 per Mcf in 2017 from $1.92 per Mcf in 2016. This increase is primarily a result of the increase in average Henry Hub natural gas index price of $1.03 per Mcf. Finally, our average realized NGL price increased 120% to $0.66 per gallon in 2017 from $0.30 per gallon in 2016.

  • Production expenses, excluding ad valorem taxes, increased 5% to $49.2 million in 2017 from $46.7 million in 2016, primarily due to increased workover and repair activity across all operating regions. On an average cost per Boe basis, production expenses excluding ad valorem taxes increased 14% to $12.89 per Boe in 2017 from $11.26 per Boe in 2016.

  • General and administrative expenses, excluding unit-based Long-Term Incentive Plan compensation expense, increased to $8.7 million in 2017 from $7.8 million in 2016 due to settlement of amounts owed by joint interest owners and cash-based employee incentive compensation plans.

  • Cash settlements received on our commodity derivatives during 2017 were $4.2 million compared to $22.8 million in 2016. The decline in cash settlements received is a result of the combination of reduced nominal volumes hedges in Q1 2017 compared to Q1 2016 as well as lower average hedge prices.

  • Total development capital expenditures increased to $23.7 million in 2017 from $4.8 million in 2016. The 2017 activity was comprised mainly of the drilling and completion of JDA wells and recompletions and workovers across all of our operating regions.

Commodity Derivative Contracts

We enter into oil and natural gas derivative contracts to help mitigate the risk of changing commodity prices. As of May 1, 2017, we had entered into derivative agreements to receive average NYMEX WTI crude oil prices and NYMEX Henry Hub, NWPL, SoCal and San Juan natural gas prices as summarized below.

WTI Crude Oil Swaps:

Time Period Volumes (Bbls) Average Price per
 Price Range per Bbl
April-December 2017 137,500  $84.75 $84.75
2018 730,000  $55.04 $55.00 - $55.15

WTI Crude Oil Costless Collars. At an annual WTI market price of $40.00, $50.00 and $65.00, the summary positions below would result in a net price of $45.00, $50.00 and $59.02, respectively for 2017 and $47.06, $50.00 and $60.29, respectively for 2018.

    Average Long Average Short
Time Period Volumes (Bbls) Put Price per Bbl Call Price per Bbl
April-December 2017 1,650,000 $45.00 $59.02
2018 1,551,250 $47.06 $60.29

WTI Crude Oil 3-Way Collars. At an annual average WTI market price of $40.00, $50.00 and $65.00, the summary position below would result in a net price of $65.00, $75.00 and $85.00, respectively.

    Average Short Put Average Long Put Average Short Call
Time Period Volumes (Bbls) Price per Bbl Price per Bbl Price per Bbl
April-June 2017 36,400  $60.00 $85.00 $104.20

WTI Crude Oil Enhanced Swaps. At an annual average WTI market price of $40.00, $50.00 and $65.00, the summary positions below would result in a net price of $65.85, $65.85 and $73.85, respectively for 2017 and $65.50, $65.50 and $73.50, respectively for 2018.

    Average Long Put Average Short Put Average Swap
Time Period Volumes (Bbls) Price per Bbl Price per Bbl Price per Bbl
April-December 2017 137,500  $57.00 $82.00 $90.85
2018 127,750  $57.00 $82.00 $90.50

Midland-to-Cushing WTI Crude Oil Differential Swaps:

Time Period Volumes (Bbls) Average Price per
 Price Range per Bbl
April-December 2017 1,650,000  $(0.30) $(0.75) - $(0.05)
2018 2,190,000  $(1.22) $(1.25) - $(1.15)

Natural Gas Swaps (Henry Hub):

    Average Price Range per
Time Period Volumes (MMBtu) Price per MMBtu MMBtu
April-December 2017 20,700,000  $3.36 $3.29 - $3.39
2018 42,200,000  $3.25 $3.04 - $3.39
2019 25,800,000  $3.36 $3.29 - $3.39

Natural Gas Costless Collars (Henry Hub). At an annual Henry Hub price of $2.50, $3.00 and $3.50, the summary position below would result in a net price of $2.90, $3.00 and $3.44, respectively.

    Average Long Put Average Short Call
Time Period Volumes (MMBtu) Price per MMBtu Price per MMBtu
April-December 2017 11,000,000 $2.90 $3.44

Natural Gas 3-Way Collars (Henry Hub). At an annual average Henry Hub market price of $2.50, $3.00 and $3.50, the summary position below would result in a net price of $3.00, $3.50 and $4.00, respectively for 2017.

  Volumes Average Short Put Average Long Put Average Short Call
Time Period  (MMBtu) Price per MMBtu Price per MMBtu Price per MMBtu
April-December 2017 3,780,000 $3.75 $4.25 $5.53

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

  April-December 2017
  Volumes (MMBtu) Price per MMBtu
NWPL 5,500,000 $(0.16)
SoCal 1,883,750 $0.11 
San Juan 1,883,750 $(0.10)

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 May 3, 2017.

Conference Call

As announced on April 19, 2017, Legacy will host an investor conference call to discuss Legacy's results on Thursday, May 4, 2017 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, May 11, 2017, by dialing 855-859-2056 or 404-537-3406 and entering replay code 7772631. Those wishing to listen to the live or archived webcast via the Internet should go to the Investor Relations tab of our website at 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

Additional Information for Holders of Legacy Units

Although Legacy has suspended distributions to both the 8% Series A and Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the "Preferred Units"), such distributions continue to accrue. Pursuant to the terms of Legacy's partnership agreement, Legacy is required to pay or set aside for payment all accrued but unpaid distributions with respect to the Preferred Units prior to or contemporaneously with making any distribution with respect to Legacy's units. Accruals of distributions on the Preferred Units are treated for tax purposes as guaranteed payments for the use of capital that will generally be taxable to the holders of such Preferred Units as ordinary income even in the absence of contemporaneous distributions.

In addition, Legacy's unitholders, just like unitholders of other master limited partnerships, are allocated taxable income irrespective of cash distributions paid. Because Legacy's unitholders are treated as partners that are allocated a share of Legacy's taxable income irrespective of the amount of cash, if any, distributed by Legacy, unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of Legacy's taxable income, including its taxable income associated with cancellation of debt ("COD income") or a disposition of property by Legacy, even if they receive no cash distributions from Legacy. As of January 21, 2016, Legacy has suspended all cash distributions to unitholders and holders of the Preferred Units. Legacy may engage in transactions to de-lever the Partnership and manage its liquidity that may result in the allocation of income and gain to its unitholders without a corresponding cash distribution. For example, during the year ended December 31, 2016, Legacy closed 26 divestitures generating net proceeds of $97.4 million, and Legacy may sell additional assets and use the proceeds to repay existing debt or fund capital expenditures, in which case Legacy's unitholders may be allocated taxable income and gain resulting from the sale, all or a portion of which may be subject to recapture rules and taxed as ordinary income rather than capital gain, without receiving a cash distribution. Further, Legacy may pursue other opportunities to reduce its existing debt, such as debt exchanges, debt repurchases, or modifications that would result in COD income being allocated to its unitholders as ordinary taxable income. The ultimate effect of any income allocations will depend on the unitholder's individual tax position with respect to that holder's units, including the availability of any current or suspended passive losses that may offset some portion of the COD income allocable to a unitholder. Unitholders are encouraged to consult their tax advisors with respect to the consequences of potential transactions that may result in income and gain to unitholders.

Additionally, if Legacy's unitholders, just like unitholders of other master limited partnerships, sell any of their units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those units. Prior distributions to unitholders that in the aggregate exceeded the cumulative net taxable income they were allocated for a unit decreased the tax basis in that unit, and will, in effect, become taxable income to Legacy's unitholders if the unit is sold at a price greater than their tax basis in that unit, even if the price received is less than original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to Legacy's unitholders due to the potential recapture items, including depreciation, depletion and intangible drilling.

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.

  Three Months Ended
  March 31,
  2017 2016
  (In thousands, except
per unit data)
Oil sales $49,142  $30,320 
Natural gas liquids (NGL) sales 5,050  2,453 
Natural gas sales 45,355  33,086 
Total revenues 99,547  65,859 
Oil and natural gas production 51,217  50,023 
Production and other taxes 4,159  2,573 
General and administrative 10,552  9,434 
Depletion, depreciation, amortization and accretion 28,796  36,959 
Impairment of long-lived assets 8,062  15,447 
Gain on disposal of assets (5,524) (31,701)
Total expenses 97,262  82,735 
Operating income (loss) 2,285  (16,876)
Other income (expense):    
Interest income 1  38 
Interest expense (20,133) (25,176)
Gain on extinguishment of debt   130,804 
Equity in income (loss) of equity method investees 11  (5)
Net gains on commodity derivatives 34,669  17,038 
Other (40) (94)
Incomes  before income taxes 16,793  105,729 
Income tax expense (421) (400)
Net income $16,372  $105,329 
Distributions to Preferred unitholders (4,750) (3,958)
Net income attributable to unitholders $11,622  $101,371 
Income per unit - basic and diluted $0.16  $1.47 
Weighted average number of units used in computing net income per unit -    
Basic and diluted 72,103  68,964 



  March 31,
 December 31,
  (In thousands)
Current assets:    
Cash and cash equivalents $1,860  $2,555 
Accounts receivable, net:    
Oil and natural gas 45,890  43,192 
Joint interest owners 21,116  23,414 
Other 2  2 
Fair value of derivatives 14,080  6,162 
Prepaid expenses and other current assets 10,343  7,447 
     Total current assets 93,291  82,772 
Oil and natural gas properties using the successful efforts method, at cost:    
Proved properties 3,328,625  3,305,856 
Unproved properties 18,518  13,448 
Accumulated depletion, depreciation, amortization and impairment (2,169,324) (2,137,395)
  1,177,819  1,181,909 
Other property and equipment, net of accumulated depreciation and amortization of $10,742
and $10,412, respectively
 3,154  3,423 
Operating rights, net of amortization of $5,468 and $5,369, respectively 1,548  1,648 
Fair value of derivatives 31,631  20,553 
Other assets 7,996  8,874 
Investments in equity method investees 658  647 
Total assets $1,316,097  $1,299,826 
Current liabilities:    
Accounts payable $4,193  $9,092 
Accrued oil and natural gas liabilities 72,367  53,248 
Fair value of derivatives 1,555  9,743 
Asset retirement obligation 2,980  2,980 
Other 20,003  11,546 
Total current liabilities 101,098  86,609 
Long-term debt 1,148,151  1,161,394 
Asset retirement obligation 271,049  269,168 
Fair value of derivatives   4,091 
Other long-term liabilities 643  643 
Total liabilities 1,520,941  1,521,905 
Commitments and contingencies    
Partners' deficit    
Series A Preferred equity - 2,300,000 units issued and outstanding at March 31, 2017
and December 31, 2016
 55,192  55,192 
Series B Preferred equity - 7,200,000 units issued and outstanding at March 31, 2017
and December 31, 2016
 174,261  174,261 
Incentive distribution equity - 100,000 units issued and outstanding at March 31, 2017
and December 31, 2016
 30,814  30,814 
Limited partners' deficit - 72,151,013 and 72,056,097 units issued and outstanding at
March 31, 2017 and December 31, 2016, respectively
 (464,969) (482,200)
General partner's deficit (approximately 0.03%) (142) (146)
Total partners' deficit (204,844) (222,079)
Total liabilities and partners' deficit $1,316,097  $1,299,826 

Non-GAAP Financial Measures

"Adjusted EBITDA" is a non-generally accepted accounting principles ("non-GAAP") measure which may be used periodically by management when discussing our financial results with investors and analysts. The following presents a reconciliation of this non-GAAP financial measure to its nearest comparable generally accepted accounting principles ("GAAP") measure.

Adjusted EBITDA is presented as management believes it provides additional information concerning the performance of our business and is 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 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.

Certain factors impacting Adjusted EBITDA 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.

"Adjusted EBITDA" should not be considered as an alternative 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:

 Three Months Ended
 March 31,
 2017 2016
 (In thousands)
Net income$16,372  $105,329 
Interest expense20,133  25,176 
Gain on extinguishment of debt  (130,804)
Income tax expense421  400 
Depletion, depreciation, amortization and accretion28,796  36,959 
Impairment of long-lived assets8,062  15,447 
Gain on disposal of assets(5,524) (31,701)
Equity in (income) loss of equity method investees(11) 5 
Unit-based compensation expense1,897  1,665 
Minimum payments received in excess of overriding royalty interest earned(1)445  802 
Net gains on commodity derivatives(34,669) (17,038)
Net cash settlements received on commodity derivatives4,236  22,777 
Transaction related expenses32  77 
Adjusted EBITDA$40,190  $29,094 

(1) Minimum payments received in excess of overriding royalties earned under a contractual agreement expiring December 31, 2019. The remaining amount of the minimum payments is recognized in net income.

Legacy Reserves LP
Dan Westcott
Executive Vice President and Chief Financial Officer

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