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Legacy Reserves Inc. Announces Third Quarter 2018 Results

MIDLAND, Texas, Oct. 31, 2018 /PRNewswire/ -- Legacy Reserves Inc. ("Legacy") (LGCY) today announced 2018 third quarter results including the following highlights:

  • Completed our corporate reorganization to become a C-Corp; commenced trading as Legacy Reserves Inc.;
  • Generated record quarterly oil production of 18,902 Bbls/d, a 5.6% increase relative to Q2'18, and 31% relative to Q3'17;
  • Brought 7 Permian horizontal wells online during the quarter, totaling 36 of such wells year-to-date;
  • Commenced Wolfcamp drilling in the Delaware Basin in Lea County, NM; preparing to mobilize Midland Basin horizontal rig from Martin to Midland County, TX;
  • Completed $21.7 million of asset sales to date since June 30, 2018, bringing our year-to-date statistics (inclusive of transactions post quarter-end) to the following:
  • Completed exchange of $130 million of Senior Notes due 2020 and 2021 for $130 million of Convertible Senior Notes due 2023 and 105,020 shares of common stock;
  • Obtained borrowing base reaffirmation at $575 million; and
  • Generated Adjusted EBITDA of $78.4 million, an 8.7% increase relative to Q2'18, from a net loss of $47.9 million.
Legacy Reserves LP Logo (PRNewsfoto/Legacy Reserves LP)

Paul T. Horne, Legacy's Chairman of the Board and Chief Executive Officer, commented, "The team completed our first quarter as a C-Corp with a bang as we delivered record oil production that represented 31% year-over-year growth. We continue to focus on our Permian development as we have maintained a rig in Lea County, New Mexico and we are about to move our second rig from Martin to Midland County. Our technical teams continue to hone our well and completion designs and, although basin-wide pressures persist, we are leveraging our long-established relationships to secure services and drive efficiencies. I am also pleased to have validated our theory that the C-Corp would enhance our access to capital as we completed a convertible exchange transaction that extends maturities and provides a path to equitize a significant portion of our debt. As mentioned in today's other press release, I am excited to see our upcoming senior management team continue our growth efforts while targeting free cash flow neutrality."

Dan Westcott, Legacy's President and Chief Financial Officer, commented, "Strong production growth drove Adjusted EBITDA higher despite a challenged Midland oil price this quarter. The team continued to execute, completing several critical, leverage-accretive asset sales. We have also moved the ball forward on several new horizontal prospects and look forward to efficiently developing that resource as we head into year-end planning for 2019."

LEGACY RESERVES INC.

SELECTED FINANCIAL AND OPERATING DATA



Three Months Ended
September 30,


Nine Months Ended
September 30,




2018


2017


2018


2017


(In thousands, except per unit data)

Revenues:








Oil sales

$

98,779


$

59,060


$

291,989


$

154,298

Natural gas liquids (NGL) sales

7,771


6,720


20,902


16,691

Natural gas sales

38,657


41,035


109,076


128,220

Total revenue

$

145,207


$

106,815


$

421,967


$

299,209

Expenses:








Oil and natural gas production, excluding ad valorem taxes

$

49,431


$

39,515


$

141,898


$

131,005

Ad valorem taxes

1,873


2,564


6,804


7,093

Total oil and natural gas production

$

51,304


$

42,079


$

148,702


$

138,098

Production and other taxes

$

7,721


$

5,475


$

22,705


$

13,779

General and administrative, excluding transaction costs and LTIP

$

9,852


$

8,418


$

27,357


$

24,087

Transaction costs

1,451


54


4,840


138

LTIP expense

6,475


1,551


32,167


4,931

Total general and administrative

$

17,778


$

10,023


$

64,364


$

29,156

Depletion, depreciation, amortization and accretion

$

39,588


$

33,715


$

114,274


$

90,200

Commodity derivative cash settlements:








Oil derivative cash settlements (paid) received

$

(1,702)


$

3,102


$

(12,905)


$

9,800

Natural gas derivative cash settlements received

$

2,919


$

3,870


$

8,913


$

7,979

Production:








Oil (MBbls)

1,739


1,323


4,915


3,404

Natural gas liquids (MGal)

11,427


11,375


32,003


27,542

Natural gas (MMcf)

15,026


15,771


43,861


46,967

Total (MBoe)

4,515


4,222


12,987


11,888

Average daily production (Boe/d)

49,076


45,891


47,571


43,542

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








Oil price (per Bbl)

$

56.80


$

44.64


$

59.41


$

45.33

Natural gas liquids price (per Gal)

$

0.68


$

0.59


$

0.65


$

0.61

Natural gas price (per Mcf)

$

2.57


$

2.60


$

2.49


$

2.73

Combined (per Boe)

$

32.16


$

25.30


$

32.49


$

25.17

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








Oil price (per Bbl)

$

55.82


$

46.99


$

56.78


$

48.21

Natural gas liquids price (per Gal)

$

0.68


$

0.59


$

0.65


$

0.61

Natural gas price (per Mcf)

$

2.77


$

2.85


$

2.69


$

2.90

Combined (per Boe)

$

32.43


$

26.95


$

32.18


$

26.67

Average WTI oil spot price (per Bbl)

$

69.69


$

48.18


$

66.93


$

49.30

Average Henry Hub natural gas index price (per MMbtu)

$

2.93


$

2.95


$

2.95


$

3.01

Average unit costs per Boe:








Oil and natural gas production, excluding ad valorem taxes

$

10.95


$

9.36


$

10.93


$

11.02

Ad valorem taxes

$

0.41


$

0.61


$

0.52


$

0.60

Production and other taxes

$

1.71


$

1.30


$

1.75


$

1.16

General and administrative excluding transaction costs and LTIP

$

2.18


$

1.99


$

2.11


$

2.03

Total general and administrative

$

3.94


$

2.37


$

4.96


$

2.45

Depletion, depreciation, amortization and accretion

$

8.77


$

7.98


$

8.80


$

7.59

Financial and Operating Results - Three-Month Period Ended September 30, 2018 Compared to Three-Month Period Ended September 30, 2017

  • Production increased 7% to 49,076 Boe/d from 45,891 Boe/d primarily due to additional oil production from our Permian Basin horizontal drilling operations and production attributable to the additional working interests under our amended and restated joint development agreement with TPG Sixth Street Partners (the "Amended and Restated Development Agreement"). This was partially offset by natural production declines and individually immaterial divestitures completed in 2018 and 2017.
  • Average realized price, excluding net cash settlements from commodity derivatives, increased 27% to $32.16 per Boe in 2018 from $25.30 per Boe in 2017 driven by an increase in oil production as a percentage of total production and the significant increase in oil prices, partially offset by widening regional differentials. Average realized oil price increased 27% to $56.80 in 2018 from $44.64 in 2017 driven by an increase in the average WTI crude oil price of $21.51 per Bbl, partially offset by the widening Mid-Cush differential. Average realized natural gas price decreased 1% to $2.57 per Mcf in 2018 from $2.60 per Mcf in 2017. This decrease is primarily the result of a decrease in NYMEX pricing, widening realized regional differentials and our adoption of ASC 606. These decreases were partially offset by an increase in Permian natural gas production which is sold inclusive of NGL content and therefore increases realized pricing for those volumes. Finally, our average realized NGL price increased 15% to $0.68 per gallon in 2018 from $0.59 per gallon in 2017.
  • Production expenses, excluding ad valorem taxes, increased to $49.4 million in 2018 from $39.5 million in 2017, primarily due to increased well count due to our Permian horizontal drilling program, increased working interests under our Amended and Restated Development Agreement and general cost inflation.
  • Non-cash impairment expense totaled $19.0 million primarily due to the write down of assets held-for-sale and the decline in natural gas futures prices.
  • General and administrative expenses, excluding unit-based Long-Term Incentive Plan ("LTIP") compensation expense, increased to $11.3 million in 2018 from $8.5 million in 2017 due to a $1.4 million increase in transaction costs and general cost increases. LTIP compensation expense increased due to the recent rise in our share price and accelerated vesting in connection with the Corporate Reorganization. Had the Corporate Reorganization not occurred, general and administrative expenses, excluding LTIP, would have decreased by $2.0 million.
  • Cash settlements received on our commodity derivatives during 2018 were $1.2 million compared to $7.0 million in 2017. The decrease in cash settlements is a result of higher commodity prices, reduced nominal volumes hedged in 2018 compared to 2017 and lower contracted hedge prices. This was partially offset by an increase in cash receipts of our Mid-Cush derivatives.
  • Total development capital expenditures decreased to $31.2 million in 2018 from $93.2 million in 2017. The 2018 activity was comprised mainly of our Permian horizontal drilling program. The 2017 activity was comprised mainly of the drilling and completion of joint development agreement wells. After the acceleration payment under our joint development agreement, we became responsible for 85% of the parties' combined interests of all remaining Tranche 1 capital costs to be paid regardless of when such costs were incurred, resulting in a larger increase in capital expenditures.

Financial and Operating Results - Nine-Month Period Ended September 30, 2018 Compared to Nine-Month Period Ended September 30, 2017

  • Production increased 9% to 47,571 Boe/d from 43,542 Boe/d primarily due to additional oil production from our Permian Basin horizontal drilling operations and production attributable to the additional working interests under the Amended and Restated Development Agreement. This was partially offset by natural production declines and individually immaterial divestitures completed in 2018 and 2017.
  • Average realized price, excluding net cash settlements from commodity derivatives, increased 29% to $32.49 per Boe in 2018 from $25.17 per Boe in 2017 driven by the significant increase in oil prices and an increase in oil production as a percentage of total production, partially offset by widening regional differentials. Average realized oil price increased 31% to $59.41 in 2018 from $45.33 in 2017 driven by an increase in the average WTI crude oil price of $17.63 per Bbl, partially offset by the widening Mid-Cush differential. Average realized natural gas price decreased 9% to $2.49 per Mcf in 2018 from $2.73 per Mcf in 2017. This decrease is a result of the decrease in the average Henry Hub natural gas index price of approximately $0.06 per Mcf, widening realized regional differentials and our adoption of ASC 606. Finally, our average realized NGL price increased 7% to $0.65 per gallon in 2018 from $0.61 per gallon in 2017 due to higher commodity prices partially offset by increased volumes with a higher percentage of lower-priced ethane.
  • Our production expenses, excluding ad valorem taxes, increased to $141.9 million in 2018 from $131.0 million in 2017. This increase was due to increased well count due to our Permian horizontal drilling program, increased working interests under our Amended and Restated Development Agreement and general cost inflation.
  • Non-cash impairment expense totaled $54.4 million related to the decline in natural gas prices and the write-down of assets held-for-sale to their fair market value.
  • General and administrative expenses, excluding unit-based LTIP compensation expense totaled $32.2 million in 2018 compared to $24.2 million in 2017, reflecting a $4.7 million increase in transaction costs and general cost increases. LTIP compensation expense increased $27.2 million due to the recent rise in our share price and accelerated vesting in connection with the Corporate Reorganization. Had the Corporate Reorganization not occurred, general and administrative expenses, excluding LTIP, would have decreased by $2.0 million.
  • Cash settlements paid on our commodity derivatives during 2018 were $4.0 million compared to cash receipts of $17.8 million in 2017. The change in cash settlements is a result of higher commodity prices, reduced nominal volumes hedged in 2018 compared to 2017 and lower contracted hedge prices. This was partially offset by an increase in cash receipts of our Mid-Cush derivatives.
  • Total development capital expenditures increased to $171.6 million in 2018 from $141.5 million in 2017. The 2018 activity was comprised mainly of our Permian horizontal drilling program.

Commodity Derivative Contracts

We enter into oil and natural gas derivative contracts to help mitigate the risk of changing commodity prices. As of October 29, 2018, we had entered into derivative agreements to receive average prices as summarized below.

NYMEX WTI Crude Oil Swaps:

Time Period


Volumes (Bbls)


Average Price per
Bbl


Price Range per Bbl

October-December 2018


763,600


$54.76


$51.20

-

$63.68

2019


3,285,000


$61.33


$57.15

-

$67.65

NYMEX 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 $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

October-December 2018


391,000


$47.06


$60.29

NYMEX 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 $65.50, $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

October-December 2018


32,200


$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

October-December 2018


1,012,000


$(1.13)


$(1.25)

-

$(0.80)

2019


2,193,000


$(3.62)


$(5.60)

-

$(1.15)

Midland-to-Cushing WTI Crude Oil Differential Enhanced Swaps

Time Period


Volumes (Bbls)


Average Short Price
Call per Bbl


Average Swap Price
per Bbl

2019


1,460,000


$70.00


$(2.91)

NYMEX Natural Gas Swaps (Henry Hub):





Average


Price Range per

Time Period


Volumes (MMBtu)


Price per MMBtu


MMBtu

October-December 2018


9,080,000


$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.

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 October 31, 2018.

Conference Call

As announced on October 17, 2018, Legacy will host an investor conference call to discuss Legacy's results on Thursday, November 1, 2018 at 9:00 a.m. (Central Time). Those wishing to participate in the conference call should dial 888-346-9287. A replay of the call will be available through Thursday, November 8, 2018, by dialing 877-344-7529 and entering replay code 10125178. Those wishing to listen to the live or archived webcast via the Internet should go to the Investor Relations tab of our website at www.LegacyReserves.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 Inc.

Legacy is an independent energy company engaged in the development, production and acquisition of oil and natural gas properties in the United States. Its current operations are focused on the horizontal development of unconventional plays in the Permian Basin and the cost-efficient management of shallow-decline oil and natural gas wells in the Permian Basin, East Texas, Rocky Mountain and Mid-Continent regions. Additional information is available at www.LegacyReserves.com.

Cautionary Statement Relevant to Forward-Looking Information

This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, including, without limitation, statements regarding the expected future growth and dividends of the company, and plans and objectives of management for future operations. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that Legacy expects, believes or anticipates will or may occur in the future, are forward-looking statements. 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 forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside the control of Legacy, which could cause results to differ materially from those expected by management of Legacy. Such risks and uncertainties include, but are not limited to, 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 Legacy's and Legacy LP's filings with the U.S. Securities and Exchange Commission, including its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. 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 INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)



Three Months Ended


Nine Months Ended


September 30,


September 30,


2018


2017


2018


2017


(In thousands, except per share / unit data)

Revenues:








Oil sales

$

98,779


$

59,060


$

291,989


$

154,298

Natural gas liquids (NGL) sales

7,771


6,720


20,902


16,691

Natural gas sales

38,657


41,035


109,076


128,220

Total revenues

145,207


106,815


421,967


299,209









Expenses:








Oil and natural gas production

51,304


42,079


148,702


138,098

Production and other taxes

7,721


5,475


22,705


13,779

General and administrative

17,778


10,023


64,364


29,156

Depletion, depreciation, amortization and accretion

39,588


33,715


114,274


90,200

Impairment of long-lived assets

18,994


14,665


54,375


24,548

(Gains) losses on disposal of assets

7,368


(2,034)


(14,172)


3,491

Total expenses

142,753


103,923


390,248


299,272









Operating income (loss)

2,454


2,892


31,719


(63)









Other income (expense):








Interest income

16


35


31


44

Interest expense

(29,383)


(23,621)


(85,340)


(64,368)

Gain on extinguishment of debt

12,107



63,800


Equity in income (loss) of equity method investees

(30)



(10)


12

Net gains (losses) on commodity derivatives

(30,867)


(13,309)


(41,886)


35,876

Other

350


403


623


765

Loss before income taxes

(45,353)


(33,600)


(31,063)


(27,734)

Income tax expense

(2,499)


(266)


(3,116)


(837)

Net loss

$

(47,852)


$

(33,866)


$

(34,179)


$

(28,571)









Loss per share / unit - basic & diluted

$

(0.46)


$

(0.34)


$

(0.33)


$

(0.29)

Weighted average number of shares / units used in computing net loss per share / unit -








Basic

104,637


100,206


104,336


99,985

Diluted

104,637


100,206


104,336


99,985

 

LEGACY RESERVES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

ASSETS



September 30, 2018


December 31, 2017



(In thousands)

Current assets:





Cash


$

3,305


$

1,246

Accounts receivable, net:





Oil and natural gas


61,109


62,755

Joint interest owners


14,516


27,420

Other


2


2

Fair value of derivatives


19,228


13,424

Prepaid expenses and other current assets


10,231


7,757

Total current assets


108,391


112,604

Oil and natural gas properties using the successful efforts method, at cost:





Proved properties


3,497,024


3,529,971

Unproved properties


28,897


28,023

Accumulated depletion, depreciation, amortization and impairment


(2,192,877)


(2,204,638)



1,333,044


1,353,356

Other property and equipment, net of accumulated depreciation and amortization of $12,179 and $11,467, respectively


2,464


2,961

Operating rights, net of amortization of $6,034 and $5,765, respectively


983


1,251

Fair value of derivatives


3,183


14,099

Other assets


3,671


8,811

Total assets


$

1,451,736


$

1,493,082

LIABILITIES AND STOCKHOLDERS' DEFICIT / PARTNERS' DEFICIT

Current liabilities:





Current debt, net


527,391


$

Accounts payable


7,838


13,093

Accrued oil and natural gas liabilities


83,216


81,318

Fair value of derivatives


39,072


18,013

Asset retirement obligation


3,214


3,214

Other


43,163


29,172

Total current liabilities


703,894


144,810

Long-term debt, net


755,784


1,346,769

Asset retirement obligation


261,260


271,472

Fair value of derivatives


12,114


1,075

Other long-term liabilities


641


643

Total liabilities


1,733,693


1,764,769

Commitments and contingencies





Partners' deficit





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



55,192

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



174,261

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



30,814

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



(531,794)

General partner's deficit (approximately 0.02%)



(160)

Common stock, $0.01 par value; 945,000,000 shares authorized, 106,113,000 shares outstanding at September 30, 2018


1,061


Additional paid-in capital


13,471


Accumulated deficit


(296,489)


Total stockholders' deficit


(281,957)


(271,687)

Total liabilities and stockholders'  / partners' deficit


$

1,451,736


$

1,493,082

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 loss to Adjusted EBITDA:


Three Months Ended


Nine Months Ended


September 30,


September 30,


2018


2017


2018


2017


(In thousands)

Net loss

$

(47,852)


$

(33,866)


$

(34,179)


$

(28,571)

      Plus:








Interest expense

29,383


23,621


85,340


64,368

Gain on extinguishment of debt

(12,107)



(63,800)


Income tax expense

2,499


266


3,116


837

Depletion, depreciation, amortization and accretion

39,588


33,715


114,274


90,200

Impairment of long-lived assets

18,994


14,665


54,375


24,548

(Gain) loss on disposal of assets

7,368


(2,034)


(14,172)


3,491

Equity in (income) loss of equity method investees

30



10


(12)

Share-based compensation expense

6,475


1,551


32,167


4,931

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

516


512


1,373


1,427

Net (gains) losses on commodity derivatives

30,867


13,309


41,886


(35,876)

Net cash settlements (paid) received on commodity derivatives

1,217


6,972


(3,992)


17,779

Transaction costs

1,451


54


4,840


138

Adjusted EBITDA(2)

$

78,429


$

58,765


$

221,238


$

143,260



(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.

(2)

Had the Corporate Reorganization not occurred on September 20, 2018, EBITDA would have increased to $80.4 million and $223.2 million for the three and nine month periods ending September 30, 2018, respectively.

 

CONTACT:

Legacy Reserves Inc.


Dan Westcott


President and Chief Financial Officer


(432) 689-5200

 

Cision

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