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Legacy Reserves LP Announces Fourth Quarter and Annual 2017 Results, Updated 2018 Guidance, Dan Westcott's Promotion to President and Availability of Schedule K-1s

MIDLAND, Texas, Feb. 21, 2018 /PRNewswire/ -- Legacy Reserves LP ("Legacy") (NASDAQ:LGCY) today announced fourth quarter and annual results for 2017, which included the following highlights:

  • Generated record quarterly production of 49,185 Boe/d, a 7% increase relative to Q3'17, and record annual production of 44,967 Boe/d.
  • Generated record quarterly oil production of 17,696 Bbls/d, a 23% increase relative to Q3'17 and record annual oil production of 13,786 Bbls/d.
  • Generated a net loss of $53.9 million for the year ended December 31, 2017.
  • Generated Adjusted EBITDA of $226.2 million for the year ended December 31, 2017, representing a 45% year-over-year increase.
  • Amended and restated our Joint Development Agreement ("JDA") with TPG Sixth Street Partners ("TSSP") and made an $141 million Acceleration Payment (the "Acceleration Payment") increasing our working interest from 20% to 85% in Tranche 1 wells and from 20% to 66.3% in a subsequent tranche of wells.
  • Entered into an agreement on December 31, 2017 to repurchase $187 million of our 6.625% Senior unsecured notes due 2021 (the "2021 Senior Notes") at $0.70 per $1.00 of principal amount. This transaction settled on January 5, 2018.
  • Entered into an agreement to amend our second lien term loan credit agreement to increase the amount of aggregate commitments from $300 million to $400 million and extend the availability of those commitments to October 25, 2019 effective January 5, 2018.
  • Meaningfully improved our credit statistics including a reduction in our Total Debt / EBITDA by 2.1x as calculated on a pro forma basis under our credit documents relative to year-end 2016.
  • Brought online an additional 5 and 30 horizontal Permian wells during the quarter and year, respectively, with an inventory of 21 drilled but uncompleted wells at December 31, 2017.

Legacy Reserves LP Logo (PRNewsfoto/Legacy Reserves LP)

Paul T. Horne, Chairman of the Board, President and Chief Executive Officer, commented, "We are excited about the progress we made in 2017 toward transitioning to a growth-oriented development company with an improved balance sheet. The Acceleration Payment, bond repurchase, expanded second lien commitments, continued efficient Permian horizontal development and prudent PDP management were instrumental in charting this path. While we are extremely proud of these cornerstone 2017 achievements, significant strides remain for us to fully realize our goals. As such, we continue to evaluate and opportunistically pursue alternatives that will enhance equity value."

Dan Westcott, Executive Vice President and Chief Financial Officer, commented, "2017 was an incredibly active year as we positioned Legacy for meaningful oil production growth that compressed leverage metrics and will drive equity value. We also reduced leverage by capturing discount in our bonds which allowed us to gain meaningful voting power in our senior notes. Undoubtedly, our operations team was the driving force in delivering our record-beating results through their continued capital-efficient horizontal development of our Permian resources and economic operation of our large PDP base. Focus on both of these arenas provided the foundation for our guidance-beating production of 49,185 Boe/d in Q4 and Adjusted EBITDA of $226.2 million in 2017 and is critical to the ongoing success of Legacy."

"While in 2016 we aimed to reduce debt outstanding, we shifted in 2017 to improve our overall credit metrics. These efforts decreased our year-over-year pro forma Total Debt / EBITDA by 2.1x. For 2018, our new financial guidance suggests Adjusted EBITDA of $330 million, a 46% increase compared to 2017. This tremendous growth hinges on our commitment to operational excellence which should continue to compress our leverage metrics as we evaluate and opportunistically pursue alternatives to change our legal and tax status, materially reduce our outstanding debt, extend our debt maturities, and otherwise position the company for long-term growth. We have a big year ahead of us and are excited for the opportunity to grow equity value through these efforts."

Proved Reserves

The following information represents estimates of our proved reserves as of December 31, 2017 which have been prepared in compliance with the SEC rules using an average WTI price, as posted by Plains Marketing L.P., of $47.79 per Bbl for oil and an average natural gas price, as posted by Platts Gas Daily, of $2.98 per MMBtu.

Operating Regions

 

Oil
(MBbls)

 

Natural

Gas
(MMcf)

 

NGLs
(MBbls)

 

Total
(MBoe)

 

%
Liquids

 

% PDP

 

% Total

 

Standardized
Measure

($ thousands)

Permian Basin

 

43,023

   

125,810

   

1,433

   

65,424

   

68

%

 

87

%

 

36

%

 

$

750,730

 

East Texas

 

79

   

343,720

   

216

   

57,582

   

1

%

 

98

%

 

32

%

 

197,186

 

Rocky Mountain

 

5,987

   

234,176

   

5,338

   

50,354

   

22

%

 

99

%

 

28

%

 

182,181

 

Mid-Continent

 

2,057

   

12,428

   

2,465

   

6,593

   

69

%

 

96

%

 

4

%

 

42,051

 

Total

 

51,146

   

716,134

   

9,452

   

179,953

   

34

%

 

94

%

 

100

%

 

$

1,172,148

 

2018 Capital Program By Category

 

Gross

 

Net

 

Percent of Net

 

(In millions)

   

Horizontal Permian development

$

290

   

$

203

   

91

%

Other drilling

34

   

5

   

2

%

Other workovers

16

   

12

   

5

%

East Texas (workovers, G&P, facilities)

3

   

3

   

1

%

Other facilities

2

   

2

   

1

%

Total capital expenditures

$

345

   

$

225

   

100

%

We serve as operator of approximately 98% of our anticipated capital program, and accordingly, maintain significant control of the capital program budget and may deviate materially from the figures above based on market conditions (or otherwise).

Updated 2018 Guidance

The following table sets forth certain assumptions used by Legacy to estimate its anticipated results of operations for 2018 based on the aforementioned expected 2018 capital program. 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."

   

FY 2018E Range

   

($ in thousands unless otherwise noted)

Production:

       

Oil (Bbls/d)

 

19,000

-

21,400

Natural gas liquids (Bbls/d)

 

1,875

-

2,075

Natural gas (MMcf/d)

 

162

-

176

Total (Boe/d)

 

47,875

-

52,808

         

Weighted average NYMEX differentials:

       

Oil (per Bbl)

 

$(4.00)

-

$(3.25)

NGL realization(1)

 

52%

-

63%

Natural gas (per Mcf)

 

$(0.35)

-

$(0.20)

         

Expenses:

       

Lease operating expenses(2)

 

$175,000

-

$195,000

Ad valorem and production taxes (% of revenue)

 

7.40%

-

7.90%

Cash G&A expenses(3)

 

$34,000

-

$38,000

         

Adjusted EBITDA(4):

 

$300,000

-

$360,000

   

(1)

Represents the projected percentage of assumed WTI crude oil prices.

(2)

Excludes ad valorem and production taxes.

(3)

Consistent with our definition of Adjusted EBITDA, these figures exclude LTIP and transaction costs.

(4)

Adjusted EBITDA is a Non-GAAP financial measure. This measure does not include pro forma adjustments permitted under our credit agreements relating to acquired and divested oil or gas properties. A reconciliation of this measure to the nearest comparable GAAP measure is available on our website.

Note: Figures above assume NYMEX strip pricing at 2/15/2018 (2018 Avg Oil $59.59 / $2.80 Gas).

Dan Westcott's Promotion to President

Effective March 1, 2018 Dan Westcott, Legacy's Chief Financial Officer will also assume the position of Legacy's President. Effective March 1, 2018, Paul Horne has resigned his position as President but will remain Chairman and Chief Executive Officer.

Mr. Horne commented, "Dan has done an outstanding job helping the company navigate the challenging landscape we have faced over the past three years. His focus and diligence on improving our financial condition and balance sheet are evident in our results. We are very excited about the future of Legacy and the critical role he has played and will play in that future. Dan's promotion to President acknowledges both and is well deserved."

Schedules K-1 Available

Legacy also announced today that it has completed the 2017 tax packages for unitholders of LGCY, LGCYP and LGCYO including Schedules K-1. Schedules K-1 for LGCYP and LGCYO each reflect $0.166667 of income for each month such security was owned in 2017 ($2.00 in total assuming a full year of ownership) irrespective of the fact that (i) no 2017 distributions were paid and (ii) the Partnership generated a net loss in 2017. Each holder of LGCY, LGCYO and LGCYP is encouraged to consult with its tax advisor with respect to the Schedule K-1 information and individual tax circumstances.

The tax packages are currently available online and may be accessed via Legacy's website at www.LegacyLP.com by clicking on the "Tax Information" link on the website. Legacy will begin mailing the Schedules K-1 to unitholders on Friday, February 23, 2018. For additional information, unitholders may also contact Legacy's K-1 Partner Data Link call center toll free at (877) 504-5606 between 8:00 a.m. and 5:00 p.m. CST Monday through Friday.

LEGACY RESERVES LP

SELECTED FINANCIAL AND OPERATING DATA

(Unaudited)

 
 

Three Months Ended

 

Twelve Months Ended

 

December 31,

 

December 31,

 

2017

 

2016

 

2017

 

2016

 

(In thousands, except per unit data)

Revenues

             

Oil sales

$

85,150

   

$

42,164

   

$

239,448

   

$

152,507

 

Natural gas liquids sales

8,105

   

5,574

   

24,796

   

15,406

 

Natural gas sales

43,837

   

43,853

   

172,057

   

146,444

 

Total revenues

$

137,092

   

$

91,591

   

$

436,301

   

$

314,357

 

Expenses:

             

Oil and natural gas production

$

42,594

   

$

41,456

   

$

173,599

   

$

169,755

 

Ad valorem taxes

2,527

   

172

   

9,620

   

9,578

 

Total

$

45,121

   

$

41,628

   

$

183,219

   

$

179,333

 

Production and other taxes

$

6,046

   

$

4,318

   

$

19,825

   

$

14,267

 

General and administrative excluding transaction costs and LTIP

$

9,919

   

$

8,237

   

$

34,006

   

$

31,196

 

Transaction costs

8,631

   

4,158

   

8,769

   

5,245

 

LTIP expense

1,666

   

1,586

   

6,597

   

7,198

 

Total general and administrative

$

20,216

   

$

13,981

   

$

49,372

   

$

43,639

 

Depletion, depreciation, amortization and accretion

$

36,738

   

$

39,719

   

$

126,938

   

$

150,414

 

Commodity derivative cash settlements:

             

Oil derivative cash settlements received

$

2,040

   

$

7,030

   

$

11,840

   

$

37,464

 

Natural gas derivative cash settlements received

4,337

   

992

   

12,316

   

27,041

 

Total commodity derivative cash settlements

$

6,377

   

$

8,022

   

$

24,156

   

$

64,505

 

Production:

             

Oil (MBbls)

1,628

   

949

   

5,032

   

4,019

 

Natural gas liquids (MGal)

10,617

   

9,111

   

38,159

   

36,757

 

Natural gas (MMcf)

15,866

   

16,243

   

62,833

   

66,824

 

Total (MBoe)

4,525

   

3,873

   

16,413

   

16,032

 

Average daily production (Boe/d)

49,185

   

42,098

   

44,967

   

43,803

 

Average sales price per unit (excluding commodity derivative cash settlements):

       

Oil price (per Bbl)

$

52.30

   

$

44.43

   

$

47.59

   

$

37.95

 

Natural gas liquids price (per Gal)

$

0.76

   

$

0.61

   

$

0.65

   

$

0.42

 

Natural gas price (per Mcf)(a)

$

2.76

   

$

2.70

   

$

2.74

   

$

2.19

 

Combined (per Boe)

$

30.30

   

$

23.65

   

$

26.58

   

$

19.61

 

Average sales price per unit (including commodity derivative cash settlements):

       

Oil price (per Bbl)

$

53.56

   

$

51.84

   

$

49.94

   

$

47.27

 

Natural gas liquids price (per Gal)

$

0.76

   

$

0.61

   

$

0.65

   

$

0.42

 

Natural gas price (per Mcf)(a)

$

3.04

   

$

2.76

   

$

2.93

   

$

2.60

 

Combined (per Boe)

$

31.71

   

$

25.72

   

$

28.05

   

$

23.63

 

Average WTI oil spot price (per Bbl)

$

55.27

   

$

49.14

   

$

50.80

   

$

43.29

 

Average Henry Hub natural gas index price (per MMbtu)

$

2.91

   

$

3.04

   

$

2.99

   

$

2.52

 

Average unit costs per Boe:

             

Production costs, excluding production and other taxes

$

9.41

   

$

10.70

   

$

10.58

   

$

10.59

 

Ad valorem taxes

$

0.56

   

$

0.04

   

$

0.59

   

$

0.60

 

Production and other taxes

$

1.34

   

$

1.11

   

$

1.21

   

$

0.89

 

General and administrative excluding transaction costs and LTIP

$

2.19

   

$

2.13

   

$

2.07

   

$

1.95

 

Total general and administrative

$

4.47

   

$

3.61

   

$

3.01

   

$

2.72

 

Depletion, depreciation, amortization and accretion

$

8.12

   

$

10.26

   

$

7.73

   

$

9.38

 

Annual Financial and Operating Results - 2017 Compared to 2016

  • Production increased 3% to an annual record of 44,967 Boe/d in 2017 from 43,803 Boe/d in 2016 primarily due to increased oil production from increased working interests as a result of the Acceleration Payment and increased Permian Basin horizontal development, partially offset by individually immaterial divestitures and natural production declines.
  • Average realized price, excluding net cash settlements from commodity derivatives, increased 36% to $26.58 per Boe in 2017 from $19.61 per Boe in 2016. Average realized oil price increased 25% to $47.59 in 2017 from $37.95 in 2016. This increase was primarily driven by an increase in the average West Texas Intermediate ("WTI") crude oil price of $7.51 per Bbl and improving realized regional differentials. Average realized natural gas price increased 25% to $2.74 per Mcf in 2017 from $2.19 per Mcf in 2016. This increase was primarily driven by an increase in the average Henry Hub natural gas index price of $0.47 per Mcf and increased natural gas volumes produced from assets in the Permian Basin which are accounted for inclusive of the NGL content contained within the natural gas volumes, resulting in a realized gas price for those assets that is higher than the NYMEX Henry Hub index price. Finally, our average realized NGL price increased 55% to $0.65 per gallon in 2017 from $0.42 per gallon in 2016.
  • Production expenses, excluding ad valorem taxes, increased 2% to $173.6 million in 2017 from $169.8 million in 2016 primarily due to increased workover and repair activity across all operating regions, increased well count due to our Permian horizontal drilling program and increased working interests as a result of the Acceleration Payment, partially offset by general cost reduction efforts. On an average cost per Boe basis, production expenses decreased to $10.58 per Boe in 2017 from $10.59 per Boe in 2016, driven primarily by increased low cost oil and NGL production.
  • Non-cash impairment expense totaled $37.3 million in 2017 primarily driven by the further decline in oil and natural gas futures prices in early 2017 as well as increased expenses and well performance during 2017.
  • General and administrative expenses, excluding transaction-related expenses and unit-based Long-Term Incentive Plan ("LTIP") compensation expense increased to $34.0 million in 2017 compared to $31.2 million in 2016 due to general cost increases.
  • Cash settlements received on our commodity derivatives during 2017 were $24.2 million as compared to $64.5 million in 2016. The decrease was due to increased average commodity prices and lower volumes under derivative contracts.
  • Total development capital expenditures increased to $176.8 million in 2017 from $29.5 million in 2016 primarily due to our increased exposure to our Permian horizontal development under our JDA.

Financial and Operating Results - Fourth Quarter 2017 Compared to Fourth Quarter 2016

  • Production increased 17% to 49,185 Boe/d from 42,098 Boe/d primarily due to increased oil production from increased working interests as a result of the Acceleration Payment and increased Permian horizontal development, partially offset by individually immaterial divestitures and natural production declines.
  • Average realized price, excluding net cash settlements from commodity derivatives, increased 28% to $30.30 per Boe in 2017 from $23.65 per Boe in 2016. Average realized oil price increased 18% to $52.30 per Bbl in 2017 from $44.43 per Bbl in 2016. This increase of $7.87 was primarily attributable to the increase in the average WTI crude oil price of $6.13 and improving realized regional differentials. Average realized natural gas prices increased 2% to $2.76 per Mcf in 2017 from $2.70 per Mcf in 2016. This increase of $0.06 was primarily attributable to increased natural gas volumes produced from assets in the Permian Basin which are accounted for inclusive of the NGL content contained within the natural gas volumes, resulting in a realized gas price for those assets that is higher than the NYMEX Henry Hub index price. This was partially offset by a decline in the average Henry Hub gas price. Finally, our average realized NGL price increased 25% to $0.76 per gallon in 2017 from $0.61 per gallon in 2016.
  • Production expenses, excluding ad valorem taxes, increased 3% to $42.6 million in 2017 from $41.5 million in 2016. Production expenses increased due to our Permian horizontal drilling program and increased working interests as a result of the Acceleration Payment partially offset by general cost reduction efforts. On a per Boe basis, production expenses decreased to $9.41 from $10.70 or 12% driven primarily by increased low cost oil production.
  • Non-cash impairment expense totaled $12.7 million in 2017 primarily driven by declining natural gas futures prices, increased costs and well performance.
  • General and administrative expenses, excluding acquisition costs and LTIP compensation expense, increased to $9.9 million in 2017 from $8.2 million in 2016 due to general cost increases.
  • Cash settlements received on our commodity derivatives were $6.4 million during 2017 compared to $8.0 million in 2016.
  • Total development capital expenditures were $35.3 million in the fourth quarter of 2017.

Commodity Derivative Contracts

We enter into oil and natural gas derivative contracts to help mitigate the risk of changing commodity prices. As of February 21, 2018, we had entered into derivative agreements to receive average NYMEX WTI crude oil prices and NYMEX Henry Hub natural gas prices as summarized below:

WTI Crude Oil Swaps:

Calendar Year

 

Volumes (Bbls)

 

Average Price per
Bbl

 

Price Range per
Bbl

2018

 

2,998,500

   

$

54.67

   

$

51.20

 

-

$

63.68

 

 

 

WTI Crude Oil Costless Collars. As an illustrative example, 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 $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

2018

 

1,551,250

 

$47.06

 

$60.29

Crude Oil Enhanced Swaps. As an illustrative example, 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 $65.50, $65.50 and $73.50, respectively for 2018.

       

Average Long Put

 

Average Short Put

 

Average Swap

Calendar Year

 

Volumes (Bbls)

 

Price per Bbl

 

Price per Bbl

 

Price per Bbl

2018

 

127,750

   

$

57.00

   

$

82.00

   

$

90.50

 

 

 

Midland-to-Cushing WTI Crude Oil Differential Swaps:

 

Time Period

 

Volumes (Bbls)

 

Average Price per
Bbl

 

Price Range per
Bbl

2018

 

4,015,000

   

$

(1.13)

   

$

(1.25)

 

-

$

(0.80)

 

2019

 

730,000

   

$

(1.15)

   

$

(1.15)

 

Natural Gas Swaps (Henry Hub):

       

Average

 

Price Range per

Calendar Year

 

Volumes (MMBtu)

 

Price per MMBtu

 

MMBtu

2018

 

36,200,000

   

$

3.23

   

$

3.04

 

-

$

3.39

 

2019

 

25,800,000

   

$

3.36

   

$

3.29

 

-

$

3.39

 

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 2017 Form 10-K which will be filed on or about February 23, 2018.

Conference Call

As announced on February 8, 2018, Legacy will host an investor conference call to discuss Legacy's results and corresponding presentation materials on Thursday, February 22, 2018 at 9:00 a.m. (Central Time). Those wishing to participate in the conference call should dial 877-870-4623. A replay of the call will be available through Thursday, March 1, 2018, by dialing 877-344-7529 and entering replay code 10116400. Those wishing to listen to the live or archived web cast via the Internet or view the corresponding presentation materials 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 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.

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, if Legacy sells assets and uses the proceeds to repay existing debt or fund capital or operating expenditures, Legacy's unitholders may be allocated taxable income and gain resulting from the sale without receiving a cash distribution. Further, if Legacy engages in debt exchanges, debt repurchases, or modifications of its existing debt, these or similar transactions could result in "cancellation of indebtedness" or COD income being allocated to Legacy's unitholders as taxable income. For tax purposes, Legacy repurchased $187 million of its 6.625% Senior Notes at $0.70 per $1.00 principal amount on December 31, 2017. Unitholders will be allocated gain and income from asset sales and COD income and may owe income tax as a result of such allocations notwithstanding the fact that Legacy has suspended cash distributions to its unitholders. The ultimate effect of any such allocations will depend on the unitholder's individual tax position with respect to its units. 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.

LEGACY RESERVES LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

 
 

Three Months Ended

 

Twelve Months Ended

 

December 31,

 

December 31,

 

2017

 

2016

 

2017

 

2016

 

(In thousands, except per unit data)

Revenues:

             

Oil sales

$

85,150

   

$

42,164

   

$

239,448

   

$

152,507

 

Natural gas liquids (NGL) sales

8,105

   

5,574

   

24,796

   

15,406

 

Natural gas sales

43,837

   

43,853

   

172,057

   

146,444

 

Total revenues

137,092

   

91,591

   

436,301

   

314,357

 

Expenses:

             

Oil and natural gas production

45,121

   

41,628

   

183,219

   

179,333

 

Production and other taxes

6,046

   

4,318

   

19,825

   

14,267

 

General and administrative

20,216

   

13,981

   

49,372

   

43,639

 

Depletion, depreciation, amortization and accretion

36,738

   

39,719

   

126,938

   

150,414

 

Impairment of long-lived assets

12,735

   

41,731

   

37,283

   

61,796

 

(Gain) loss on disposal of assets

(1,885)

   

(806)

   

1,606

   

(50,095)

 

Total expenses

118,971

   

140,571

   

418,243

   

399,354

 

Operating income (loss)

18,121

   

(48,980)

   

18,058

   

(84,997)

 

Other income (expense):

             

Interest income

20

   

13

   

64

   

67

 

Interest expense

(24,838)

   

(16,502)

   

(89,206)

   

(79,060)

 

Gain on extinguishment of debt

   

   

   

150,802

 

Equity in income of equity method investees

5

   

7

   

17

   

 

Net gains (losses) on commodity derivatives

(18,100)

   

(38,913)

   

17,776

   

(41,224)

 

Other

27

   

309

   

792

   

(179)

 

Loss before income taxes

(24,765)

   

(104,066)

   

(52,499)

   

(54,591)

 

Income tax expense

(561)

   

(519)

   

(1,398)

   

(1,229)

 

Net Loss

$

(25,326)

   

$

(104,585)

   

$

(53,897)

   

$

(55,820)

 

Distributions to preferred unitholders

(4,750)

   

(5,542)

   

(19,000)

   

(19,000)

 

Net loss attributable to unitholders

$

(30,076)

   

$

(110,127)

   

$

(72,897)

   

$

(74,820)

 

Loss per unit — basic and diluted

$

(0.41)

   

$

(1.53)

   

$

(1.01)

   

$

(1.06)

 

Weighted average number of units used in computing loss per unit —

             

Basic and diluted

72,595

   

72,056

   

72,405

   

70,605

 

 

LEGACY RESERVES LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

 
 

December 31,

 

2017

 

2016

 

(In thousands)

ASSETS

Current assets:

     

Cash

$

1,246

   

$

2,555

 

Accounts receivable, net:

     

Oil and natural gas

62,755

   

43,192

 

Joint interest owners

27,420

   

23,414

 

Other

2

   

2

 

Fair value of derivatives

13,424

   

6,162

 

Prepaid expenses and other current assets

7,757

   

7,447

 

Total current assets

112,604

   

82,772

 

Oil and natural gas properties, at cost:

     

Proved oil and natural gas properties using the successful efforts method of accounting

3,529,971

   

3,305,856

 

Unproved properties

28,023

   

13,448

 

Accumulated depletion, depreciation, amortization and impairment

(2,204,638)

   

(2,137,395)

 
 

1,353,356

   

1,181,909

 

Other property and equipment, net of accumulated depreciation and amortization of $11,467 and $10,412, respectively

2,961

   

3,423

 

Operating rights, net of amortization of $5,765 and $5,369, respectively

1,251

   

1,648

 

Fair value of derivatives

14,099

   

20,553

 

Other assets

8,811

   

9,521

 

Total assets

$

1,493,082

   

$

1,299,826

 
 

LIABILITIES AND PARTNERS' DEFICIT

Current liabilities:

     

Accounts payable

$

13,093

   

$

9,092

 

Accrued oil and natural gas liabilities

81,318

   

53,248

 

Fair value of derivatives

18,013

   

9,743

 

Asset retirement obligation

3,214

   

2,980

 

Other

29,172

   

11,546

 

Total current liabilities

144,810

   

86,609

 

Long-term debt

1,346,769

   

1,161,394

 

Asset retirement obligation

271,472

   

269,168

 

Fair value of derivatives

1,075

   

4,091

 

Other long-term liabilities

643

   

643

 

Total liabilities

1,764,769

   

1,521,905

 

Commitments and contingencies

     

Partners' equity (deficit):

     

Series A Preferred equity - 2,300,000 units issued and outstanding at December 31, 2017 and December 31, 2016

55,192

   

55,192

 

Series B Preferred equity - 7,200,000 units issued and outstanding at December 31, 2017 and December 31, 2016

174,261

   

174,261

 

Incentive distribution equity - 100,000 units issued and outstanding at December 31, 2017 and December 31, 2016

30,814

   

30,814

 

Limited partners' deficit - 72,594,620 and 72,056,097 units issued and outstanding at December 31, 2017 and 2016, respectively

(531,794)

   

(482,200)

 

       General partner's deficit (approximately 0.03%)

(160)

   

(146)

 

   Total partners' deficit

(271,687)

   

(222,079)

 

Total liabilities and partners' deficit

$

1,493,082

   

$

1,299,826

 

Non-GAAP Financial Measures

This press release, the financial tables and other supplemental information include "Adjusted EBITDA" which 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. Consistent with practices common to publicly traded partnerships, the board of directors of our general partner historically has not varied the distribution it declares based on such timing effects.

"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.

Adjusted EBITDA is defined as net income (loss) plus:

  • Interest expense;
  • (Gain) loss on extinguishment of debt;
  • Income tax expense (benefit);
  • Depletion, depreciation, amortization and accretion;
  • Impairment of long-lived assets;
  • (Gain) loss on sale of partnership investment;
  • Loss (gain) 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 costs.

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

 

Three Months Ended

 

Twelve Months Ended

 

December 31,

 

December 31,

 

2017

 

2016

 

2017

 

2016

 

(In thousands)

Net loss

$

(25,326)

   

$

(104,585)

   

$

(53,897)

   

$

(55,820)

 

      Plus:

             

Interest expense

24,838

   

16,502

   

89,206

   

79,060

 

Gain on debt extinguishment

   

   

   

(150,802)

 

Income tax expense

561

   

519

   

1,398

   

1,229

 

Depletion, depreciation, amortization and accretion

36,738

   

39,719

   

126,938

   

150,414

 

Impairment of long-lived assets

12,735

   

41,731

   

37,283

   

61,796

 

(Gain) loss on disposal of assets

(1,885)

   

(806)

   

1,606

   

(50,095)

 

Equity in income of equity method investees

(5)

   

(7)

   

(17)

   

 

Unit-based compensation expense

1,666

   

1,586

   

6,597

   

7,198

 

Minimum payments received in excess of overriding royalty interest earned(1)

509

   

434

   

1,936

   

1,659

 

Net (gains) losses on commodity derivatives

18,100

   

38,913

   

(17,776)

   

41,224

 

Net cash settlements received on commodity derivatives

6,377

   

8,022

   

24,156

   

64,505

 

Transaction costs

8,631

   

4,158

   

8,769

   

5,245

 

Adjusted EBITDA

$

82,939

   

$

46,186

   

$

226,199

   

$

155,613

 
   

(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 are recognized in net income.

CONTACT:
Legacy Reserves LP
Dan Westcott
Executive Vice President and Chief Financial Officer
432-689-5200

 

 

SOURCE Legacy Reserves LP