|
Sean T. Wheeler, P.C.
Enoch Varner Kirkland & Ellis LLP 609 Main Street Houston, Texas 77002 (713) 836-3600 |
| |
Catherine Gallagher
Michael Swidler Baker Botts L.L.P. 700 K Street N.W. Washington, DC 20001 (202) 639-7700 |
| |
Kenneth Jackman
Srinivas M. Raju Richards, Layton & Finger, P.A. One Rodney Square, 920 King Street Wilmington, DE 19801 (302) 651-7700 |
|
a.
|
☐
|
The filing of solicitation materials or an information statement subject to Regulation 14A, Regulation 14C or Rule 13e-3(c) under the Securities Exchange Act of 1934. |
b.
|
☐
|
The filing of a registration statement under the Securities Act of 1933. |
c.
|
☐
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A tender offer. |
d.
|
☒
|
None of the above. |
| | |
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| | | | 88 | | | |
| | | | A-1 | | | |
| | | | B-1 | | | |
| | | | C-1 | | | |
| | | | D-1 | | |
Multiple
|
| |
Mean
|
| |
Median
|
| ||||||
Enterprise Value / 2022 EBITDA
|
| | | | 8.5x | | | | | | 8.4x | | |
Enterprise Value / 2023 EBITDA
|
| | | | 8.0x | | | | | | 7.9x | | |
Price / NAV
|
| | | | 0.85x | | | | | | N/A | | |
Date Announced
|
| |
Target
|
| |
Acquiror
|
| |
EV/LTM EBITDA
|
|
1/13/2021
|
| |
Golar LNG Partners, LP
|
| |
New Fortress Energy Inc.
|
| |
6.3x
|
|
2/2/2021
|
| |
GasLog Ltd.
|
| |
BlackRock
|
| |
10.6x
|
|
10/4/2021
|
| |
Teekay LNG Partners L.P.
|
| |
Stonepeak Limestone Holdings LP
|
| |
8.6x
|
|
In US$ millions
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |
2026E
|
| |
2027E
|
| |
2028E
|
| |||||||||||||||||||||
Revenues
|
| | | | 147 | | | | | | 142 | | | | | | 143 | | | | | | 136 | | | | | | 126 | | | | | | 103 | | | | | | 107 | | |
Operating and administrative expenses
|
| | | | (40) | | | | | | (37) | | | | | | (39) | | | | | | (39) | | | | | | (40) | | | | | | (40) | | | | | | (41) | | |
EBITDA (excl share of result of JVs)
|
| | | | 107 | | | | | | 104 | | | | | | 103 | | | | | | 97 | | | | | | 85 | | | | | | 63 | | | | | | 66 | | |
In US$ millions
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |
2026E
|
| |
2027E
|
| |
2028E
|
| |||||||||||||||||||||
Change in Cash
|
| | | | (19) | | | | | | 1 | | | | | | 3 | | | | | | 36 | | | | | | 43 | | | | | | 19 | | | | | | 23 | | |
Ending Cash Balance
|
| | | | 23 | | | | | | 25 | | | | | | 28 | | | | | | 63 | | | | | | 106 | | | | | | 125 | | | | | | 148 | | |
RCF Available Drawings
|
| | | | 9 | | | | | | 39 | | | | | | 63 | | | | | | 63 | | | | | | — | | | | | | — | | | | | | — | | |
In US$ millions
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |
2026E
|
| |
2027E
|
| |
2028E
|
| |||||||||||||||||||||
Revenues
|
| | | | 146 | | | | | | 138 | | | | | $ | 137 | | | | | | 132 | | | | | | 122 | | | | | | 99 | | | | | | 103 | | |
Operating and administrative expenses
|
| | | | (40) | | | | | | (37) | | | | | | (40) | | | | | | (39) | | | | | | (40) | | | | | | (40) | | | | | | (41) | | |
EBITDA (excl share of result of JVs)
|
| | | | 107 | | | | | | 101 | | | | | | 97 | | | | | | 93 | | | | | | 82 | | | | | | 59 | | | | | | 62 | | |
In US$ millions
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |
2026E
|
| |
2027E
|
| |
2028E
|
| |||||||||||||||||||||
Change in Cash
|
| | | | (19) | | | | | | 1 | | | | | | (1) | | | | | | 26 | | | | | | 39 | | | | | | 16 | | | | | | 19 | | |
Ending Cash Balance
|
| | | | 23 | | | | | | 25 | | | | | | 23 | | | | | | 49 | | | | | | 88 | | | | | | 104 | | | | | | 123 | | |
RCF Available Drawings
|
| | | | 9 | | | | | | 37 | | | | | | 58 | | | | | | 63 | | | | | | — | | | | | | — | | | | | | — | | |
In US$ millions
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |
2026E
|
| |
2027E
|
| |
2028E
|
| |||||||||||||||||||||
Revenues
|
| | | | 141 | | | | | | 103 | | | | | | 104 | | | | | | 97 | | | | | | 87 | | | | | | 64 | | | | | | 68 | | |
Operating and administrative expenses
|
| | | | (38) | | | | | | (26) | | | | | | (27) | | | | | | (28) | | | | | | (28) | | | | | | (28) | | | | | | (29) | | |
EBITDA (excl share of result of JVs)
|
| | | | 103 | | | | | | 77 | | | | | | 76 | | | | | | 69 | | | | | | 58 | | | | | | 36 | | | | | | 39 | | |
In US$ millions
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |
2026E
|
| |
2027E
|
| |
2028E
|
| |||||||||||||||||||||
Change in Cash
|
| | | | 14 | | | | | | 15 | | | | | | 37 | | | | | | 36 | | | | | | 33 | | | | | | 9 | | | | | | 12 | | |
Ending Cash Balance
|
| | | | 56 | | | | | | 71 | | | | | | 108 | | | | | | 144 | | | | | | 177 | | | | | | 186 | | | | | | 198 | | |
RCF Available Drawings
|
| | | | 34 | | | | | | 63 | | | | | | 63 | | | | | | 63 | | | | | | — | | | | | | — | | | | | | — | | |
In US$ millions
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |
2026E
|
| |
2027E
|
| |
2028E
|
| |||||||||||||||||||||
Revenues
|
| | | | 141 | | | | | | 103 | | | | | | 125 | | | | | | 129 | | | | | | 119 | | | | | | 96 | | | | | | 100 | | |
Operating and administrative expenses
|
| | | | (39) | | | | | | (35) | | | | | | (37) | | | | | | (37) | | | | | | (38) | | | | | | (38) | | | | | | (39) | | |
EBITDA (excl share of result of JVs)
|
| | | | 102 | | | | | | 68 | | | | | | 88 | | | | | | 92 | | | | | | 81 | | | | | | 59 | | | | | | 62 | | |
In US$ millions
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |
2026E
|
| |
2027E
|
| |
2028E
|
| |||||||||||||||||||||
Change in Cash
|
| | | | 66 | | | | | | (85) | | | | | | 15 | | | | | | 35 | | | | | | 32 | | | | | | 8 | | | | | | 12 | | |
Ending Cash Balance
|
| | | | 108 | | | | | | 23 | | | | | | 37 | | | | | | 72 | | | | | | 104 | | | | | | 113 | | | | | | 124 | | |
RCF Available Drawings
|
| | | | 34 | | | | | | 56 | | | | | | 63 | | | | | | 63 | | | | | | — | | | | | | — | | | | | | — | | |
In US$ millions
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |
2026E
|
| |
2027E
|
| |
2028E
|
| |||||||||||||||||||||
Revenues
|
| | | | 141 | | | | | | 103 | | | | | | 125 | | | | | | 129 | | | | | | 119 | | | | | | 96 | | | | | | 100 | | |
Operating and administrative expenses
|
| | | | (39) | | | | | | (35) | | | | | | (37) | | | | | | (37) | | | | | | (38) | | | | | | (38) | | | | | | (39) | | |
EBITDA (excl share of result of JVs)
|
| | | | 102 | | | | | | 68 | | | | | | 88 | | | | | | 92 | | | | | | 81 | | | | | | 59 | | | | | | 62 | | |
In US$ millions
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |
2026E
|
| |
2027E
|
| |
2028E
|
| |||||||||||||||||||||
Change in Cash
|
| | | | 7 | | | | | | (25) | | | | | | (1) | | | | | | 5 | | | | | | 32 | | | | | | 8 | | | | | | 12 | | |
Ending Cash Balance
|
| | | | 48 | | | | | | 24 | | | | | | 23 | | | | | | 28 | | | | | | 60 | | | | | | 68 | | | | | | 80 | | |
RCF Available Drawings
|
| | | | 34 | | | | | | 12 | | | | | | 34 | | | | | | 63 | | | | | | — | | | | | | — | | | | | | — | | |
In US$ millions
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |
2026E
|
| |
2027E
|
| |
2028E
|
| |||||||||||||||||||||
Revenues
|
| | | | 148 | | | | | | 149 | | | | | | 104 | | | | | | 113 | | | | | | 119 | | | | | | 96 | | | | | | 100 | | |
Operating and administrative expenses
|
| | | | (41) | | | | | | (41) | | | | | | (37) | | | | | | (37) | | | | | | (38) | | | | | | (38) | | | | | | (39) | | |
EBITDA (excl share of result of JVs)
|
| | | | 108 | | | | | | 108 | | | | | | 67 | | | | | | 76 | | | | | | 81 | | | | | | 59 | | | | | | 62 | | |
In US$ millions
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |
2026E
|
| |
2027E
|
| |
2028E
|
| |||||||||||||||||||||
Change in Cash
|
| | | | (20) | | | | | | (3) | | | | | | (2) | | | | | | (1) | | | | | | (11) | | | | | | 25 | | | | | | 12 | | |
Ending Cash Balance
|
| | | | 23 | | | | | | 20 | | | | | | 18 | | | | | | 17 | | | | | | 6 | | | | | | 31 | | | | | | 43 | | |
RCF Available Drawings
|
| | | | 9 | | | | | | 43 | | | | | | 49 | | | | | | 4 | | | | | | — | | | | | | — | | | | | | — | | |
In US$ millions
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |
2026E
|
| |
2027E
|
| |
2028E
|
| |||||||||||||||||||||
Revenues
|
| | | | 148 | | | | | | 149 | | | | | | 149 | | | | | | 142 | | | | | | 131 | | | | | | 108 | | | | | | 112 | | |
Operating and administrative expenses
|
| | | | (41) | | | | | | (41) | | | | | | (38) | | | | | | (38) | | | | | | (39) | | | | | | (38) | | | | | | (39) | | |
EBITDA (excl share of result of JVs)
|
| | | | 108 | | | | | | 108 | | | | | | 111 | | | | | | 104 | | | | | | 93 | | | | | | 70 | | | | | | 73 | | |
In US$ millions
|
| |
2022E
|
| |
2023E
|
| |
2024E
|
| |
2025E
|
| |
2026E
|
| |
2027E
|
| |
2028E
|
| |||||||||||||||||||||
Change in Cash
|
| | | | (20) | | | | | | (3) | | | | | | 15 | | | | | | 47 | | | | | | 50 | | | | | | 27 | | | | | | 30 | | |
Ending Cash Balance
|
| | | | 23 | | | | | | 20 | | | | | | 35 | | | | | | 82 | | | | | | 132 | | | | | | 159 | | | | | | 189 | | |
RCF Available Drawings
|
| | | | 9 | | | | | | 39 | | | | | | 63 | | | | | | 63 | | | | | | — | | | | | | — | | | | | | — | | |
| | |
Amount to be
Paid |
|
Financial advisory fee and expenses
|
| | $11 million | |
Legal, accounting and other professional fees
|
| | $4 million | |
Proxy solicitation, printing and mailing costs and filing fees
|
| |
$0.1 million
|
|
Transfer agent and paying agent fees and expenses
|
| |
$0.1 million
|
|
Insurance premiums and other costs and expenses
|
| | $6 million | |
Total
|
| |
$21.2 million
|
|
| | |
As of
|
| |||||||||||||||
| | |
March 31,
2022 (unaudited) |
| |
December 31,
2021 (audited) |
| |
December 31,
2020 (audited) |
| |||||||||
Non-current assets
|
| | | $ | 939,147 | | | | | $ | 932,728 | | | | | $ | 926,652 | | |
Current assets
|
| | | | 72,850 | | | | | | 71,280 | | | | | | 55,158 | | |
Total assets
|
| | | | 1,011,997 | | | | | | 1,004,008 | | | | | | 981,810 | | |
8.75% Series A preferred units:
|
| | | | 176,078 | | | | | | 176,078 | | | | | | 167,760 | | |
Common units public:
|
| | | | 326,173 | | | | | | 317,515 | | | | | | 308,850 | | |
Common units Parent:
|
| | | | 62,945 | | | | | | 52,626 | | | | | | 46,277 | | |
Accumulated other comprehensive income (loss)
|
| | | | (1,413) | | | | | | (15,699) | | | | | | (29,572) | | |
Total equity
|
| | | | 563,783 | | | | | | 530,520 | | | | | | 493,315 | | |
Current liabilities
|
| | | | 95,614 | | | | | | 76,209 | | | | | | 77,808 | | |
Non-current liabilities
|
| | | | 352,600 | | | | | | 397,279 | | | | | | 410,687 | | |
Total liabilities
|
| | | | 448,214 | | | | | | 473,488 | | | | | | 488,495 | | |
Total equity and liabilities
|
| | | $ | 1,011,997 | | | | | $ | 1,004,008 | | | | | $ | 981,810 | | |
| | |
Three Months Ended
|
| |
Year Ended
|
| ||||||||||||||||||
| | |
March 31,
2022 (unaudited) |
| |
March 31,
2021 (unaudited) |
| |
December 31,
2021 (audited) |
| |
December 31,
2020 (audited) |
| ||||||||||||
Total Revenues
|
| | | $ | 35,310 | | | | | $ | 34,776 | | | | | $ | 141,260 | | | | | $ | 143,095 | | |
Total Operating Expenses
|
| | | | (15,457) | | | | | | (14,117) | | | | | | (61,673) | | | | | | (54,749) | | |
Equity in earnings (losses) of joint ventures
|
| | | | 8,634 | | | | | | 11,073 | | | | | | 25,836 | | | | | | 6,420 | | |
Operating income (loss)
|
| | | | 28,487 | | | | | | 31,732 | | | | | | 105,423 | | | | | | 94,766 | | |
Total financial income (expense), net
|
| | | | (5,507) | | | | | | (6,178) | | | | | | (29,138) | | | | | | (26,057) | | |
Income before tax
|
| | | | 22,980 | | | | | | 25,554 | | | | | | 76,285 | | | | | | 68,709 | | |
Income tax benefit (expense)
|
| | | | (2,819) | | | | | | (1,716) | | | | | | (16,290) | | | | | | (5,564) | | |
Net income (loss)
|
| | | $ | 20,161 | | | | | $ | 23,838 | | | | | $ | 59,995 | | | | | $ | 63,145 | | |
Preferred unitholders’ interest in net income
|
| | | | 3,877 | | | | | | 3,877 | | | | | | 15,508 | | | | | | 14,802 | | |
Limited partners’ interest in net income (loss)
|
| | | $ | 16,284 | | | | | $ | 19,961 | | | | | $ | 44,487 | | | | | $ | 48,343 | | |
Earnings per unit | | | | | | | | | | | | | | | | | | | | | | | | | |
Common unit public (basic and diluted)
|
| | | $ | 0.49 | | | | | $ | 0.59 | | | | | $ | 1.32 | | | | | $ | 1.40 | | |
Common unit Parent (basic and diluted)
|
| | | $ | 0.49 | | | | | $ | 0.61 | | | | | $ | 1.35 | | | | | $ | 1.51 | | |
| | |
Common Unit
Price Ranges |
| |
Cash Distribution Paid
Per Common Unit |
| ||||||||||||
| | |
High
|
| |
Low
|
| ||||||||||||
Period from July 1, 2022 to July 7, 2022
|
| | | $ | 9.00 | | | | | $ | 8.97 | | | | | $ | | | |
Quarter Ended June 30, 2022
|
| | | $ | 9.10 | | | | | $ | 6.06 | | | | | $ | | | |
Quarter Ended March 31, 2022
|
| | | $ | 7.89 | | | | | $ | 4.22 | | | | | $ | 0.01 | | |
Year Ended December 31, 2021 | | | | | | | | | | | | | | | | | | | |
Quarter Ended December 31, 2021
|
| | | $ | 5.43 | | | | | $ | 3.93 | | | | | $ | 0.01 | | |
Quarter Ended September 30, 2021
|
| | | $ | 18.06 | | | | | $ | 4.28 | | | | | $ | 0.01 | | |
Quarter Ended June 30, 2021
|
| | | $ | 17.95 | | | | | $ | 14.81 | | | | | $ | 0.01 | | |
Quarter Ended March 31, 2021
|
| | | $ | 17.02 | | | | | $ | 14.49 | | | | | $ | 0.44 | | |
Year Ended December 31, 2020 | | | | | | | | | | | | | | | | | | | |
Quarter Ended December 31, 2020
|
| | | $ | 14.98 | | | | | $ | 10.93 | | | | | $ | 0.44 | | |
Quarter Ended September 30, 2020
|
| | | $ | 11.82 | | | | | $ | 9.21 | | | | | $ | 0.44 | | |
Quarter Ended June 30, 2020
|
| | | $ | 13.13 | | | | | $ | 5.35 | | | | | $ | 0.44 | | |
Quarter Ended March 31, 2020
|
| | | $ | 16.72 | | | | | $ | 5.10 | | | | | $ | 0.44 | | |
| | |
Common Units
Beneficially Owned |
| |||||||||
Name of Beneficial Owner
|
| |
Number
|
| |
Percent
|
| ||||||
Höegh LNG Holdings Ltd.(1)
|
| | | | 15,257,498 | | | | | | 45.7% | | |
John V. Veech (Chairman of the Board of Directors)
|
| | | | * | | | | | | * | | |
David Spivak
|
| | | | * | | | | | | * | | |
Kathleen MacAllister
|
| | | | * | | | | | | * | | |
Robert G. Shaw
|
| | | | * | | | | | | * | | |
Timothy Faries
|
| | | | * | | | | | | * | | |
Alberto Donzelli
|
| | | | * | | | | | | * | | |
Carlo Ravizza
|
| | | | * | | | | | | * | | |
Håvard Furu (Chief Financial Officer & interim Chief Executive Officer)
|
| | | | * | | | | | | * | | |
All directors and executive officers as a group (8 persons)
|
| | | | 45,370 | | | | | | * | | |
|
Höegh LNG Holdings Ltd.
Canon’s Court 22 Victoria Street Hamilton, HM 12, Bermuda Attention: Corporate Secretary Phone: +1 441 298 3300 |
| |
Höegh LNG Partners LP
Canon’s Court 22 Victoria Street Hamilton, HM 12 Bermuda Attention: Corporate Secretary Phone: +1 441 298 3300 |
|
| | | | | A-2 | | | |
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| | | | | A-23 | | |
Defined Term
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Where used
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Adverse Recommendation Change
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Section 5.3(a)
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Affiliate
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Section 8.13
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Agreement
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Preamble
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Antitrust Laws
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Section 8.13
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Book-Entry Units
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Section 2.1(f)
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business day
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Section 8.13
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Certificate
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Section 2.1(f)
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Certificate of Merger
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Section 1.3
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Charter Documents
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Section 8.13
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Closing
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Section 1.2
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Closing Date
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Section 1.2
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Code
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Section 2.2(h)
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Common Unit
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Section 8.13
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Common Unitholders
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Section 8.13
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Conflicts Committee
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Recitals
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Contract
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Section 8.13
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COVID-19
|
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Section 8.13
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COVID-19 Measures
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Section 8.13
|
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Effective Time
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Section 1.3
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Exchange Act
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Section 3.4
|
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Exchange Fund
|
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Section 2.2(b)
|
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Financial Advisor
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Section 3.7
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GAAP
|
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Section 8.13
|
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General Partner
|
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Preamble
|
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General Partner Approval
|
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Recitals
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General Partner Board
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Recitals
|
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General Partner Charter Documents
|
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Section 8.13
|
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General Partner Interest
|
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Section 8.13
|
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Governmental Authority
|
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Section 8.13
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HSR Act
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Section 8.13
|
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Incentive Distribution Right
|
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Section 8.13
|
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Indemnified Person
|
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Section 5.8(a)
|
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Knowledge
|
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Section 8.13
|
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Law
|
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Section 8.13
|
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Liens
|
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Section 8.13
|
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Long-Term Incentive Plan
|
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Section 8.13
|
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Marshall Islands LLC Act
|
| |
Section 8.13
|
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Marshall Islands LP Act
|
| |
Section 8.13
|
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Material Contract
|
| |
Section 8.13
|
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Maximum Amount
|
| |
Section 5.8(c)
|
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Measurement Date
|
| |
Section 3.2(a)
|
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Merger
|
| |
Section 1.1
|
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Merger Consideration
|
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Section 2.1(a)
|
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Merger Sub
|
| |
Preamble
|
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Defined Term
|
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Where used
|
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MLP
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Preamble
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Recitals
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| |
Section 5.1(b)
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MLP Charter Documents
|
| |
Section 8.13
|
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MLP Disclosure Schedule
|
| |
Article III
|
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MLP Material Adverse Effect
|
| |
Section 8.13
|
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MLP Notice Period
|
| |
Section 5.3(b)(ii)
|
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MLP SEC Documents
|
| |
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|
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NYSE
|
| |
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|
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| |
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|
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Parent
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Parent Board
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Recitals
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Partnership Agreement
|
| |
Section 8.13
|
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|
| |
Section 8.13
|
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Party
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Preamble
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| |
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|
| |
Section 8.13
|
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|
| |
Section 8.13
|
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|
| |
Section 8.13
|
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Proxy Statement
|
| |
Section 3.4
|
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Representatives
|
| |
Section 5.1(a)
|
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Required Regulatory Approvals
|
| |
Section 6.1(b)
|
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Restraints
|
| |
Section 6.1(c)
|
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Schedule 13E-3
|
| |
Section 5.1(a)
|
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SEC
|
| |
Section 8.13
|
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Securities Act
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|
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Series A Preferred Unit
|
| |
Section 8.13
|
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|
| |
Section 8.13
|
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Special Approval
|
| |
Section 8.13
|
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Sponsor Entities
|
| |
Preamble
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Sponsor Units
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Section 2.1(d)
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|
| |
Section 8.13
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|
| |
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|
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Support Agreement
|
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Recitals
|
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|
| |
Section 1.1
|
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Tax
|
| |
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|
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Tax Return
|
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|
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|
| |
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|
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Unaffiliated Unitholders
|
| |
Section 8.13
|
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Unitholder
|
| |
Section 8.13
|
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Unitholder Approval
|
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Section 6.1(a)
|
|
Unitholders Meeting
|
| |
Section 5.1(b)
|
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Exhibit (c)(2)
CONFIDENTIAL TREATMENT REQUESTED | &RQIOLFWV&RPPLWWHHRI+|HJK/1*3DUWQHUV/3 'LVFXVVLRQ0DWHULDOV January 21, 2022 |
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Exhibit (c)(5)
CONFIDENTIAL TREATMENT REQUESTED | Conflicts Committee of Höegh LNG Partners LP Discussion Materials May 16, 2022 PRELIMINARY DRAFT SUBJECT TO MATERIAL CHANGES 5/15/2022 12:37 PM |
Preliminary Draft – Confidential These materials have been prepared by Evercore Group L.L.C. (“Evercore”) for the Conflicts Committee of the Board of Directors (the “Committee”) of Höegh LNG Partners LP (the “Partnership”) to whom such materials are directly addressed and delivered and may not be used or relied upon for any purpose other than as specifically contemplated. These materials are based on information provided by or on behalf of the Partnership and/or other potential transaction participants, from public sources or otherwise reviewed by Evercore. Evercore assumes no responsibility for independent investigation or verification of such information and has relied on such information being complete and accurate in all material respects. To the extent such information includes estimates and forecasts of future financial performance prepared by or reviewed with the management of the Partnership and/or other potential transaction participants or obtained from public sources, Evercore has assumed that such estimates and forecasts have been reasonably prepared on bases reflecting the best currently available estimates and judgments of such management (or, with respect to estimates and forecasts obtained from public sources, represent reasonable estimates). No representation or warranty, express or implied, is made as to the accuracy or completeness of such information and nothing contained herein is, or shall be relied upon as, a representation, whether as to the past, the present or the future. These materials were designed for use by specific persons familiar with the business and affairs of the Partnership. These materials are not intended to provide the sole basis for evaluating, and should not be considered a recommendation with respect to, any transaction or other matter. These materials have been developed by and are proprietary to Evercore and were prepared exclusively for the benefit and internal use of the Committee. These materials were compiled on a confidential basis for use by the Committee in evaluating the potential transaction described herein and not with a view to public disclosure or filing thereof under state or federal securities laws, and may not be reproduced, disseminated, quoted or referred to, in whole or in part, without the prior written consent of Evercore. These materials do not constitute an offer or solicitation to sell or purchase any securities and are not a commitment by Evercore (or any affiliate) to provide or arrange any financing for any transaction or to purchase any security in connection therewith. Evercore assumes no obligation to update or otherwise revise these materials. These materials may not reflect information known to other professionals in other business areas of Evercore and its affiliates. Evercore and its affiliates do not provide legal, accounting or tax advice. Accordingly, any statements contained herein as to tax matters were neither written nor intended by Evercore or its affiliates to be used and cannot be used by any taxpayer for the purpose of avoiding tax penalties that may be imposed on such taxpayer. Each person should seek legal, accounting and tax advice based on his, her or its particular circumstances from independent advisors regarding the impact of the transactions or matters described herein. |
Preliminary Draft – Confidential I II III Table of Contents Section Situation Overview Summary of Key Findings from Poten Valuation of the Common Units Appendix |
Preliminary Draft – Confidential I. Situation Overview |
Preliminary Draft – Confidential We have seen a significant firming of the energy complex generally, and FSRU market specifically, due to increased geo-political risk and dislocation of Russian natural gas attributable to the Ukraine invasion Energy security and the need for natural gas from non-Russian sources has created significant additional demand for FSRUs f 9-10 FSRUs likely to be deployed in Europe FSRU rates for prompt units suitable for that market have increased dramatically with capex rates in excess of $150k per day f Appraisal values of FSRUs have increased reflecting stronger fundamentals f Newbuilding prices have also increased for LNG/FSRU vessels Increased public market interest in the FSRU space, demonstrated by the highly successful IPO of Excelerate Energy The Sponsor updated its indication of interest on April 12th with an indicative offer of $8.00 per unit On May 9th, New Fortress Energy sent the Board of the Partnership an unsolicited offer of $12.00 per unit for all LP units outstanding, contingent on termination of the existing management and administrative services agreements between the Partnership and the Sponsor f Sponsor’s advisors have verbally reiterated to Evercore that they will not consider New Fortress Energy’s offer, but the Sponsor/Partnership has not formally given notice to that effect Recent Events 1 |
Preliminary Draft – Confidential $6.18 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 12/6/21 1/1/22 1/27/22 2/23/22 3/21/22 4/16/22 5/13/22 Unit Price Performance Since 12/3/21 Offer Source: FactSet (as of 5/13/22) Publicly Disclosed $4.25 Offer Price on 12/3/21 2 $8.00 HMLP Offer on 4/12/22 $12.00 NFE Offer on 5/9/22 |
Preliminary Draft – Confidential II. Summary of Key Findings from Poten |
Preliminary Draft – Confidential FSRUs are now a well-established technology and solution, and given current market circumstances, demand has rapidly accelerated f Energy security / the impact of Russian invasion of Ukraine is a material accelerant of demand f High LNG prices may cause demand destruction for price-sensitive projects Asia / other emerging markets New FSRU supply is virtually non-existent as there are no imminent newbuildings or conversions f Conversions are becoming more expensive ($50-80mm+ foregone revenue), and conversion candidates will have limitations / disadvantages to ships purpose-built as FSRUs f Timing of newbuilds is 3-4 years (2026) versus 18 months Newbuild LNG/FSRU prices have increased significantly in the last year, and capex rates tend to be highly correlated with newbuild prices f Charter rates are extremely high for prompt availability into Europe, particularly for closed loop / high-spec vessels f Current rates are in the $125-150k range per day, though only a discrete number of vessels may be deployed at these levels f With newbuilding prices high, capex rates may stay above $120k per day in the short term Conversion costs and upgrade costs have materially increased The Partnership’s vessels have a number of trading limitations due to technical specifications that may be suboptimal for many users Summary of Key Findings Source: Poten Partners 5 |
Preliminary Draft – Confidential Given the Partnership’s FSRUs have 8+ years of average remaining duration, they will be unable to exploit the full upside from the current supply/demand dynamic Downside scenarios of the Lampung are possible, but the impact is likely less severe than management predicts, given the lack of alternative vessels for PGN HMLP’s fleet has some identified technological disadvantages that may negatively impact the rates the vessels are able to earn Lampung upgrade costs are now estimated by management to be more than double the original estimates; Poten generally agreed with this conclusion Management’s projected drydock schedule may be too infrequent and/or may reflect too low of drydock costs; if this were the case, the Partnership’s cash flows would be negatively impacted Recharter rates are very difficult to predict and rates predicted by Poten are similar to Management’s forecast Key Takeaways for the Partnership Source: Poten Partners 6 |
Preliminary Draft – Confidential Estimated total of ~60 projects by 2030, requiring around 15 additional FSRUs f Diversification from Russian supply and displacement of other fuels drives European FSRU demand and restricts FSRU availability elsewhere f Currently there is a requirement for 4 FSRUs in Germany, 2 in Italy, 1 in France, 1 in Poland, 1 in Latvia and 1 shared FSRU for Finland and Estonia f It is likely that other European countries will be looking for FSRUs as the conflict continues f Asia, the Middle East and South America all have large growth potential but are more price-sensitive than Europe ● Several projects are likely to be delayed due to current elevated LNG costs FSRU supply is limited in the short-term f No contracted FSRU newbuildings f Many LNGC vessels are not suitable for conversion and with the increase in projected LNG demand, the economics for FSRU conversion may not make sense f There is a multi-year lag before newbuilds can fill the shortfall and converted LNGCs will not be suitable for many projects Positive FSRU Supply / Demand Dynamics FSRU Supply and Demand 0 10 20 30 40 50 60 70 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 # of FSRUs Americas Europe Middle East Indian Subcontinent South East Asia Africa Other APAC Supply Source: Poten Partners 7 FSRU demand expected to exceed supply through 2030 |
Preliminary Draft – Confidential III. Valuation of the Common Units |
Preliminary Draft – Confidential NAV Useful Life DCF Peer Trading Precedents Based on Low and High Equity Research Price Targets Equity Research Price Targets 1 Charter Free Net Asse t Va lue EV / 2022E EBITDA EV / 2023E EBITDA Price / NAV Based on High and Low Midpoint DCF Values Across Management Cases TEV / LTM EBITDA 52-Week Common Unit Price Range Premiums Paid Based on 25th and 75th percentile of the One-Day, One-Week and One-Month Premiums Paid Management Cases Appraised Asset Value Sensitivity: ± 5.0% 2022E EBITDA Multiple: 7.0x – 9.0x 2023E EBITDA Multiple: 6.5x – 8.5x Price / NAV Multiple: 0.70x – 1.05x LTM EBITDA Multiple: 7.0x – 10.5x $9.65 $4.97 $8.16 $6.50 $7.87 $6.52 $3.77 $4.68 $5.00 $12.85 $11.21 $14.63 $12.95 $11.81 $17.01 $8.17 $6.10 $9.50 $11.25 $8.09 $11.39 $9.72 $9.84 $11.77 $ - $5.00 $10.00 $15.00 $20.00 $18.17 HLNG Revised Offer: $8.00 NFE Price Indication: $12.00 Unit price (as of 5/13/22): $6.18 Original HLNG Offer: $4.25 Valuation of the Common Units Summary Valuation of the Common Units 8 For Reference Only 52-week Range Range since distribution cut2 Source: Partnership Management, FactSet (as of 5/13/22), Duff & Phelps 2022 Valuation Handbook, Wall Street research Note: This summary of certain analyses is provided for illustrative purposes. It does not represent all of the analyses performed by Evercore and should be considered with the information elsewhere in this presentation 1. Price target estimates include B Riley estimate of $5.00 as of 11/19/21 (subsequent $4.25 price target predicated on the offer price being accepted) and Stifel estimate of $9.50 as of 3/28/22 2. On July 27, 2021 HMLP announced a reduction in the quarterly cash distribution per common unit from $0.44 to $0.01 |
Preliminary Draft – Confidential Fleet Three fully-owned vessels Two 50% ownership joint venture vessels Assumed useful life of 35-years per vessel Utilization Utilization based on drydock and offhire schedules Drydock assumed in five year increments for each vessel Offhire assumed as 20 days, except for Lampung and Grace, which are assumed as 24 and 30 days, respectively TCE Rates / Revenue Build Assumes that ships roll to spot rate business post completion of scheduled charter expiration1 Expenses / Costs Direct expenses, corporate G&A, dry docking expense and baseline vessel opex assumed to grow at 5.0% inflation over 2023 and 2024 and 2.0% thereafter Assumes the below annual corporate level expenses2: Scrap Value Assumes the below scrap values and scrap dates: Valuation of the Common Units Scenario Analysis – Key Assumptions per Partnership Management 11 Source: Partnership Management 1. PGN FSRU Lampung sensitized across cases which consider the early termination of its current charter 2. Figures in 2022 nominal values 3. Excludes $4.0mm addback for corporate G&A synergies Vessel Scrap Value Scrap Date PGN FSRU Lampung $13.5 4/22/49 Höegh Gallant 13.5 11/4/49 Höegh Grace 13.5 3/29/51 Neptune 12.1 11/30/44 Cape Ann 12.1 6/1/45 ($ in millions, except per day data) Income Tax Witholding Tax G&A Expenses3 PGN FSRU Lampung $6.4 $1.6 Höegh Gallant 0.2 0.1 Höegh Grace 2.6 0.3 Total $9.2 $2.0 $7.2 |
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION. | Preliminary Draft – Confidential Valuation of the Common Units Case 1 PGN contract is amended starting in November 2022 f Capex rate is reduced from $ to $ f Contract length is extended 5 years f Vessel ownership is transferred to PGN at the end of the contract (Nov. 2039) for $ Case 2 PGN contract is amended starting in November 2022 f Capex rate is reduced from $ to $ f Contract length is extended 5 years f Vessel ownership is transferred to PGN at the end of the contract (Nov. 2039) for $ Case 3 PGN buys the vessel for $ in November 2022 and the contract terminates Case 4 PGN pays $ to HMLP to terminate the contract in November 2022 Lampung is idle for 18 months - upgraded for $75mm and incurs opex while idle Redeployed at a capex rate of $ , and operated for remaining useful life. Assumes 10 year contract duration for new employment and 9 months idle time between each renewal with $5mm class renewal cost Case 5 PGN pays $ m to HMLP to terminate the contract in November 2022 Lampung is idle for 18 months - upgraded for $75mm and incurs opex while idle Redeployed at a capex rate of $ , and operated for remaining useful life. Assumes 10 year contract duration for new employment and 9 months idle time between each renewal with $5mm class renewal cost Case 6 PGN wins arbitration and the contract is terminated in January 2024 without any compensation Lampung is idle for 18 months - upgraded for $75mm and incurs opex while idle Redeployed at a capex rate of $ , and operated for remaining useful life. Assumes 10 year contract duration for new employment and 9 months idle time between each renewal with $5mm class renewal cost Case 7 PGN contract remains in place through 2034, the vessel is upgraded for $75mm assumed idle for four months; incurs opex while idle Redeployed at a capex rate of $ , and operated for remaining useful life. Assumes 10 year contract duration for new employment and 9 months idle time between each renewal with $5mm class renewal cost 13 Source: Partnership Management Partnership Management Cases: Lampung Scenarios |
Preliminary Draft – Confidential Valuation of the Common Units Useful Life Discounted Cash Flow Analysis by Case 14 Source: Partnership Management, FactSet (as of 5/13/22), Duff & Phelps 2022 Valuation Handbook, Wall Street research Note: Indicated valuation ranges based on sensitivity analysis assuming WACC of 8.00% to 9.00% and assuming midpoint recharter capex rates sensitized by ± 5.0% Partnership Management Cases Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 7 $8.46 $7.62 $10.06 $6.93 $5.28 $3.49 $9.19 $11.23 $10.34 $12.47 $10.15 $8.49 $6.60 $12.19 $9.78 $8.92 $11.21 $8.46 $6.81 $4.97 $10.62 $3.00 $5.00 $7.00 $9.00 $11.00 $13.00 |
Preliminary Draft – Confidential Appendix |
Preliminary Draft – Confidential Excelerate Energy – Broker Growth Estimates Source: FactSet (5/13/22) 28 ($ in millions, except per share data) Broker Forecasted EBITDA Broker Forecasted Dividends per Share $0.08 $0.11 $0.13 $0.24 2022E 2023E 2024E 2025E $262 $308 $339 $502 2022E 2023E 2024E 2025E 24.1% CAGR 41.5% CAGR |
Exhibit (c)(6)
CONFIDENTIAL TREATMENT REQUESTED | Conflicts Committee of Höegh LNG Partners LP Discussion Materials May 21, 2022 PRELIMINARY DRAFT SUBJECT TO MATERIAL CHANGES 5/21/2022 8:41 AM |
Preliminary Draft – Confidential These materials have been prepared by Evercore Group L.L.C. (“Evercore”) for the Conflicts Committee of the Board of Directors (the “Committee”) of Höegh LNG Partners LP (the “Partnership”) to whom such materials are directly addressed and delivered and may not be used or relied upon for any purpose other than as specifically contemplated. These materials are based on information provided by or on behalf of the Partnership and/or other potential transaction participants, from public sources or otherwise reviewed by Evercore. Evercore assumes no responsibility for independent investigation or verification of such information and has relied on such information being complete and accurate in all material respects. To the extent such information includes estimates and forecasts of future financial performance prepared by or reviewed with the management of the Partnership and/or other potential transaction participants or obtained from public sources, Evercore has assumed that such estimates and forecasts have been reasonably prepared on bases reflecting the best currently available estimates and judgments of such management (or, with respect to estimates and forecasts obtained from public sources, represent reasonable estimates). No representation or warranty, express or implied, is made as to the accuracy or completeness of such information and nothing contained herein is, or shall be relied upon as, a representation, whether as to the past, the present or the future. These materials were designed for use by specific persons familiar with the business and affairs of the Partnership. These materials are not intended to provide the sole basis for evaluating, and should not be considered a recommendation with respect to, any transaction or other matter. These materials have been developed by and are proprietary to Evercore and were prepared exclusively for the benefit and internal use of the Committee. These materials were compiled on a confidential basis for use by the Committee in evaluating the potential transaction described herein and not with a view to public disclosure or filing thereof under state or federal securities laws, and may not be reproduced, disseminated, quoted or referred to, in whole or in part, without the prior written consent of Evercore. These materials do not constitute an offer or solicitation to sell or purchase any securities and are not a commitment by Evercore (or any affiliate) to provide or arrange any financing for any transaction or to purchase any security in connection therewith. Evercore assumes no obligation to update or otherwise revise these materials. These materials may not reflect information known to other professionals in other business areas of Evercore and its affiliates. Evercore and its affiliates do not provide legal, accounting or tax advice. Accordingly, any statements contained herein as to tax matters were neither written nor intended by Evercore or its affiliates to be used and cannot be used by any taxpayer for the purpose of avoiding tax penalties that may be imposed on such taxpayer. Each person should seek legal, accounting and tax advice based on his, her or its particular circumstances from independent advisors regarding the impact of the transactions or matters described herein. |
Preliminary Draft – Confidential I II III Table of Contents Section Situation Overview Summary of Key Findings from Poten Valuation of the Common Units Appendix |
Preliminary Draft – Confidential I. Situation Overview |
Preliminary Draft – Confidential We have seen a significant firming of the energy complex generally, and FSRU market specifically, due to increased geo-political risk and dislocation of Russian natural gas attributable to the Ukraine invasion Energy security and the need for natural gas from non-Russian sources has created significant additional demand for FSRUs f 9-10 FSRUs likely to be deployed in Europe FSRU rates for prompt units suitable for that market have increased dramatically with capex rates in excess of $150k per day f Appraisal values of FSRUs have increased reflecting stronger fundamentals f Newbuilding prices have also increased for LNG/FSRU vessels Increased public market interest in the FSRU space, demonstrated by the highly successful IPO of Excelerate Energy The Sponsor updated its indication of interest on April 12th with an indicative offer of $8.00 per unit On May 9th, New Fortress Energy sent the Board of the Partnership an unsolicited offer of $12.00 per unit for all LP units outstanding, contingent on termination of the existing management and administrative services agreements between the Partnership and the Sponsor f Sponsor’s advisors have verbally reiterated to Evercore that they will not consider New Fortress Energy’s offer, but the Sponsor/Partnership has not formally given notice to that effect On May 17th, the Committee countered the Sponsor’s indicative offer of $8.00 per unit with an $11.00 per unit offer f On May 18th and 19th the Sponsor rejected the $11.00 offer, terminated negotiations and indicated intentions to issue a press release announcing that they were pulling their offer f On May 20th, in a series of communications between the Sponsor, Committee and both parties’ advisors, the Sponsor agreed to postpone announcing the termination of negotiations for 48 hours, so both parties could conduct a final round of price discovery ● The Sponsor further indicated that any counter the Committee puts forth should “start with an 8”, or as interpreted by the Committee and its advisors, be in the $8.00-8.99 range Recent Events 1 |
Preliminary Draft – Confidential $6.73 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 12/6/21 1/2/22 1/30/22 2/26/22 3/26/22 4/22/22 5/20/22 Unit Price Performance Since 12/3/21 Offer Source: FactSet (as of 5/20/22) Publicly Disclosed $4.25 Offer Price on 12/3/21 2 $8.00 HMLP Offer on 4/12/22 $12.00 NFE Offer on 5/9/22 |
Preliminary Draft – Confidential II. Summary of Key Findings from Poten |
Preliminary Draft – Confidential FSRUs are now a well-established technology and solution, and given current market circumstances, demand has rapidly accelerated f Energy security / the impact of Russian invasion of Ukraine is a material accelerant of demand f High LNG prices may cause demand destruction for price-sensitive projects Asia / other emerging markets New FSRU supply is virtually non-existent as there are no imminent newbuildings or conversions f Conversions are becoming more expensive ($50-80mm+ foregone revenue), and conversion candidates will have limitations / disadvantages to ships purpose-built as FSRUs f Timing of newbuilds is 3-4 years (2026) versus 18 months Newbuild LNG/FSRU prices have increased significantly in the last year, and capex rates tend to be highly correlated with newbuild prices f Charter rates are extremely high for prompt availability into Europe, particularly for closed loop / high-spec vessels f Current rates are in the $125-150k range per day, though only a discrete number of vessels may be deployed at these levels f With newbuilding prices high, capex rates may stay above $120k per day in the short term Conversion costs and upgrade costs have materially increased The Partnership’s vessels have a number of trading limitations due to technical specifications that may be suboptimal for many users Summary of Key Findings Source: Poten Partners 5 |
Preliminary Draft – Confidential Given the Partnership’s FSRUs have 8+ years of average remaining duration, they will be unable to exploit the full upside from the current supply/demand dynamic Downside scenarios of the Lampung are possible, but the impact is likely less severe than management predicts, given the lack of alternative vessels for PGN HMLP’s fleet has some identified technological disadvantages that may negatively impact the rates the vessels are able to earn Lampung upgrade costs are now estimated by management to be more than double the original estimates; Poten generally agreed with this conclusion Management’s projected drydock schedule may be too infrequent and/or may reflect too low of drydock costs; if this were the case, the Partnership’s cash flows would be negatively impacted Recharter rates are very difficult to predict and rates predicted by Poten are relatively similar to Management’s forecast Key Takeaways for the Partnership Source: Poten Partners 6 |
Preliminary Draft – Confidential Estimated total of ~60 projects by 2030, requiring around 15 additional FSRUs f Diversification from Russian supply and displacement of other fuels drives European FSRU demand and restricts FSRU availability elsewhere f Currently there is a requirement for 4 FSRUs in Germany, 2 in Italy, 1 in France, 1 in Poland, 1 in Latvia and 1 shared FSRU for Finland and Estonia f It is likely that other European countries will be looking for FSRUs as the conflict continues f Asia, the Middle East and South America all have large growth potential but are more price-sensitive than Europe ● Several projects are likely to be delayed due to current elevated LNG costs FSRU supply is limited in the short-term f No contracted FSRU newbuildings f Many LNGC vessels are not suitable for conversion and with the increase in projected LNG demand, the economics for FSRU conversion may not make sense f There is a multi-year lag before newbuilds can fill the shortfall and converted LNGCs will not be suitable for many projects Positive FSRU Supply / Demand Dynamics FSRU Supply and Demand 0 10 20 30 40 50 60 70 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 # of FSRUs Americas Europe Middle East Indian Subcontinent South East Asia Africa Other APAC Supply Source: Poten Partners 7 FSRU demand expected to exceed supply through 2030 |
Preliminary Draft – Confidential III. Valuation of the Common Units |
Preliminary Draft – Confidential NAV Useful Life DCF Peer Trading Precedents Price / NAV Multiple: 0.70x – 1.05x LTM EBITDA Multiple: 7.0x – 10.5x Based on Low and High Equity Research Price Targets Equity Research Price Targets 1 Charter Free Net Asse t Va lue EV / 2022E EBITDA EV / 2023E EBITDA Price / NAV Appraised Asset Value Sensitivity: ± 5.0% Based on High and Low Midpoint DCF Values Across Management Cases TEV / LTM EBITDA 52-Week Common Unit Price Range Premiums Paid Based on 25th and 75th percentile of the One-Day, One-Week and One-Month Premiums Paid Management Cases 2022E EBITDA Multiple: 7.0x – 9.0x 2023E EBITDA Multiple: 6.5x – 8.5x $9.42 $3.42 $7.94 $6.28 $7.72 $6.30 $3.77 $4.68 $5.00 $12.62 $9.79 $14.40 $12.72 $11.57 $16.79 $8.17 $6.10 $9.50 $11.02 $6.61 $11.17 $9.50 $9.65 $11.54 $ - $5.00 $10.00 $15.00 $20.00 $18.17 HLNG Revised Offer: $8.00 NFE Price Indication: $12.00 Unit price (as of 5/20/22): $6.73 Original HLNG Offer: $4.25 Valuation of the Common Units Summary Valuation of the Common Units 8 For Reference Only 52-week Range Range since distribution cut2 Source: Partnership Management, FactSet (as of 5/20/22), Duff & Phelps 2022 Valuation Handbook, Wall Street research Note: This summary of certain analyses is provided for illustrative purposes. It does not represent all of the analyses performed by Evercore and should be considered with the information elsewhere in this presentation. As compared with the draft of the materials presented to the Committee on May 16, 2022, the useful life discounted cash flow analysis shown herein does not consider the illustrative $4mm of annual G&A synergies the Partnership may be able to achieve from a take-private transaction. As is customary in similar transactions, the valuation analysis contained herein assesses the Partnership on a standalone basis. The previously considered $4mm in annual synergies represents $1.32 per unit of value at a discount rate of 8.50%. 1. Price target estimates include B Riley estimate of $5.00 as of 11/19/21 (subsequent $4.25 price target predicated on the offer price being accepted) and Stifel estimate of $9.50 as of 3/28/22 2. On July 27, 2021 HMLP announced a reduction in the quarterly cash distribution per common unit from $0.44 to $0.01 |
Preliminary Draft – Confidential Fleet Three fully-owned vessels Two 50% ownership joint venture vessels Assumed useful life of 35-years per vessel Utilization Utilization based on drydock and offhire schedules Drydock assumed in five year increments for each vessel Offhire assumed as 20 days, except for Lampung and Grace, which are assumed as 24 and 30 days, respectively TCE Rates / Revenue Build Assumes that ships roll to spot rate business post completion of scheduled charter expiration1 Expenses / Costs Direct expenses, corporate G&A, dry docking expense and baseline vessel opex assumed to grow at 5.0% inflation over 2023 and 2024 and 2.0% thereafter Assumes the below annual corporate level expenses2: Scrap Value Assumes the below scrap values and scrap dates: Valuation of the Common Units Scenario Analysis – Key Assumptions per Partnership Management 11 Source: Partnership Management 1. PGN FSRU Lampung sensitized across cases which consider the early termination of its current charter 2. Figures in 2022 nominal values Ve sse l Scrap Value Scrap Date PGN FSRU Lampung $13.5 4/22/49 Höegh Gallant 13.5 11/4/49 Höegh Grace 13.5 3/29/51 Neptune 12.1 11/30/44 Cape Ann 12.1 6/1/45 ($ in millions, except per day data) Ve sse l Income Tax Withholding Tax G&A Expenses PGN FSRU Lampung $6.4 $1.6 Höegh Gallant 0.2 0.1 Höegh Grace 2.6 0.3 Total $9.2 $2.0 $7.2 |
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION. | Preliminary Draft – Confidential Valuation of the Common Units Case 1 PGN contract is amended starting in November 2022 f Capex rate is reduced from $ to $ f Contract length is extended 5 years f Vessel ownership is transferred to PGN at the end of the contract (Nov. 2039) for $ Case 2 PGN contract is amended starting in November 2022 f Capex rate is reduced from $ to $ f Contract length is extended 5 years f Vessel ownership is transferred to PGN at the end of the contract (Nov. 2039) for $ Case 3 PGN buys the vessel for $ in November 2022 and the contract terminates Case 4 PGN pays $ to HMLP to terminate the contract in November 2022 Lampung is idle for 18 months - upgraded for $75mm and incurs opex while idle Redeployed at a capex rate of $ , and operated for remaining useful life. Assumes 10 year contract duration for new employment and 9 months idle time between each renewal with $5mm class renewal cost Case 5 PGN pays $ to HMLP to terminate the contract in November 2022 Lampung is idle for 18 months - upgraded for $75mm and incurs opex while idle Redeployed at a capex rate of $ , and operated for remaining useful life. Assumes 10 year contract duration for new employment and 9 months idle time between each renewal with $5mm class renewal cost Case 6 PGN wins arbitration and the contract is terminated in January 2024 without any compensation Lampung is idle for 18 months - upgraded for $75mm and incurs opex while idle Redeployed at a capex rate of $ , and operated for remaining useful life. Assumes 10 year contract duration for new employment and 9 months idle time between each renewal with $5mm class renewal cost Case 7 PGN contract remains in place through 2034, the vessel is upgraded for $75mm assumed idle for four months; incurs opex while idle Redeployed at a capex rate of $ , and operated for remaining useful life. Assumes 10 year contract duration for new employment and 9 months idle time between each renewal with $5mm class renewal cost 13 Source: Partnership Management Partnership Management Cases: Lampung Scenarios |
Preliminary Draft – Confidential Valuation of the Common Units Useful Life Discounted Cash Flow Analysis by Case 14 Source: Partnership Management, FactSet (as of 5/20/22), Duff & Phelps 2022 Valuation Handbook, Wall Street research Note: Indicated valuation ranges based on sensitivity analysis assuming WACC of 8.00% to 9.00% and assuming midpoint recharter capex rates sensitized by ± 5.0%. As compared with the draft of the materials presented to the Committee on May 16, 2022, the useful life discounted cash flow analysis shown herein does not consider the illustrative $4mm of annual G&A synergies the Partnership may be able to achieve from a take-private transaction. As is customary in similar transactions, the valuation analysis contained herein assesses the Partnership on a standalone basis. The previously considered $4mm in annual synergies represents $1.32 per unit of value at a discount rate of 8.50%. Partnership Management Cases Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 7 $7.09 $6.25 $8.69 $5.56 $3.92 $2.00 $7.70 $9.75 $8.86 $10.99 $8.67 $7.01 $5.00 $10.59 $8.36 $7.50 $9.79 $7.04 $5.39 $3.42 $9.07 $ - $3.00 $6.00 $9.00 $12.00 |
Preliminary Draft – Confidential Appendix |
Preliminary Draft – Confidential Excelerate Energy – Broker Growth Estimates Source: FactSet (5/20/22) 28 ($ in millions, except per share data) Broker Forecasted EBITDA Broker Forecasted Dividends per Share $0.08 $0.11 $0.13 $0.24 2022E 2023E 2024E 2025E $262 $308 $339 $502 2022E 2023E 2024E 2025E 24.1% CAGR 41.5% CAGR |
Exhibit (c)(7)
CONFIDENTIAL TREATMENT REQUESTED
Conflicts Committee of Höegh LNG Partners LP Discussion Materials May [25], 2022 PRELIMINARY DRAFT SUBJECT TO MATERIAL CHANGES 5/24/2022 11:10 AM |
Preliminary Draft – Confidential I II III IV Table of Contents Section Introduction Overview of Evercore Process Situation Overview Valuation of the Common Units Appendix |
Preliminary Draft – Confidential I. Introduction |
Preliminary Draft – Confidential Introduction Evercore Group L.L.C. (“Evercore”) is pleased to provide the materials herein to the Conflicts Committee of the Board of Directors (the “Committee”) of Höegh LNG Partners LP (“HMLP” or the “Partnership”), regarding the proposed acquisition by Höegh LNG Holdings Ltd. (“Höegh LNG” or the “Sponsor”) of all outstanding common units of HMLP (the “Common Units”) not already owned by the Sponsor or its affiliates (the “Unaffiliated Unitholders”) and “buy in” HMLP, which will cease to be a publicly traded (the “Proposed Transaction”), in exchange for $9.25 in cash per Common Unit (the “Merger Consideration”) f The Merger Consideration, represents a 135.4% premium to HMLP’s unaffected closing unit price of $3.93 as of December 3, 2021, one trading day prior to the Sponsor’s original offer of $4.25 per Common Unit (the “Initial Offer”), and a 34.8% premium to HMLP’s closing unit price of $6.86 as of May 23, 2022 ● The Merger Consideration represents a 117.6% increase from the Initial Offer, which represented an 8.1% premium to HMLP’s unaffected closing unit price of $3.93 as of December 3, 2021 The following materials review the Proposed Transaction, and include: f An introduction, including an overview of the Proposed Transaction, a summary of proposed terms, an overview of the Partnership’s current summary organizational structure and ownership, an analysis of financial metrics implied by the Proposed Transaction and certain issues for consideration f An overview of Evercore’s process to evaluate the Proposed Transaction f An overview of HMLP’s current market situation and business overview f A review of the financial projections for HMLP as provided by Partnership Management and a review of the assumptions utilized by Partnership Management in deriving such financial projections f A valuation of the Common Units Overview of the Materials Source: Partnership Management, Partnership materials, FactSet 1 |
Preliminary Draft – Confidential Introduction Transaction Overview Source: Management Projections, Partnership materials, FactSet (as of 5/23/22), Bloomberg (as of 5/23/22) 1. Includes Morten W. Höegh’s 1.3% ownership of total outstanding common units 2. VWAPs from Bloomberg as of 5/23/22 Buyer Höegh LNG Holdings Ltd., which currently owns approximately 47% of the total outstanding common units1 along with the non-economic GP interest in the Partnership Höegh LNG is beneficially owned by Larus Holdings, a joint venture between Leif Höegh & Co. and Morgan Stanley Infrastructure Partners Proposed Transaction Summary Höegh LNG submitted an offer to purchase the approximately 53% of outstanding common units not already owned by the Sponsor or its affiliates and “buy in” HMLP, which will cease to be a publicly traded entity The Transaction would be structured as a merger between the Partnership and a subsidiary of Höegh LNG, with the Partnership surviving the merger as a subsidiary of Höegh LNG Consideration Unaffiliated Unitholders will receive $9.25 in cash for each common unit held, a 34.8% premium to HMLP’s current unit price and a 41.8% premium to the 30-day VWAP2 Based on the $9.25 per unit offer price, the Unaffiliated Unitholders would receive total cash consideration of $163.3mm for their approximately 53.0% outstanding common interest in HMLP Implied TEV of the Proposed Transaction is $773.5mm Timing & Approvals Approval of Conflicts Committee of Board of Directors of HMLP, Board of Directors of HMLP and Board of Directors of Höegh LNG The Proposed Transaction assumes transaction will be subject to approval by holders of the majority of the outstanding HMLP common units Other The Proposed Transaction will be taxable to the Unaffiliated Unitholders The Proposed Transaction will be subject to SEC Rule 13E-3 The Preferred Series A units are to remain unchanged and outstanding 2 Opinion Requested: Evercore has been asked by the Conflicts Committee, whether, in Evercore’s opinion, as of the date of the opinion, the Merger Consideration to be paid in the Proposed Transaction is fair, from a financial point of view, to the Partnership’s Unaffiliated Unitholders |
Preliminary Draft – Confidential Introduction Transaction Overview A subsidiary of Höegh LNG to merge with and into the Partnership, with the Partnership surviving the merger as a subsidiary of Höegh LNG Consideration Each Common Unit, other than Common Units held by Sponsor and its affiliates will be converted into the right to receive $9.25 per Common Unit in cash without any interest Key Conditions to Closing Approval by majority of the outstanding Common Units Required clearances No injunction prohibiting the merger Bring down of reps and warranties, performance of covenants No MAE (Sponsor condition) Certain third-party consents (listed on a schedule) (Sponsor condition) Deal Protection [The Partnership is subject to no-shop restrictions; the Conflicts Committee may change recommendation, subject to five business-day re-negotiation right obligation] The Partnership may not change recommendation or terminate to accept superior proposal and is required to submit transaction to unitholders vote (“force the vote”) Regulatory Efforts Parties obligated to use reasonable best efforts to obtain regulatory approvals necessary for closing, but parties are not obligated to agree to any disposition or behavioral or other remedies Timing Outside Date: November 23, 2022 Source: Draft, dated May [24], 2022, of Agreement and Plan of Merger 3 Selected Terms of the Merger Agreement TBU – Subject to Final Merger Agreement |
Preliminary Draft – Confidential Simple Value # Institutional Holders Units (000s) % of Position1 1 JPMorgan Securities LLC 927 2.8% $6,360 2 Renaissance Technologies LLC 706 2.1% 4,846 3 Prescott Group Capital Management LLC 551 1.7% 3,780 4 Invesco Advisers, Inc. 481 1.4% 3,300 5 Verition Fund Management LLC 279 0.8% 1,917 6 Citigroup Global Markets, Inc. 272 0.8% 1,868 7 Marshall Wace LLP 142 0.4% 973 8 Privium Fund Management (UK) Ltd. 62 0.2% 427 9 Belvedere Trading LLC 46 0.1% 318 10 Maven Investment Partners US Ltd. 45 0.1% 308 -- Other 256 0.8% 1,755 Total Institutional Holders 3,769 11.3% $25,852 Total Implied L.P. Retail Holders 13,890 41.6% $95,286 Simple Value # L.P. Insiders Units (000s) % of Position 1 Hoegh Lng Holdings Ltd. 15,257 45.7% $104,666 2 Morten W. Hoegh 441 1.3% 3,026 3 Stohle Sveinung J S 16 0.0% 109 Total L.P. Insiders 15,714 47.1% $107,801 Total L.P. Units 33,373 100.0% $228,939 Total Partnership Common Units 33,373 100.0% $228,939 Introduction Organizational Structure and Ownership Summary Current Ownership Breakdown Unitholder Ownership Structure¹ Höegh LNG Partners LP 45.4% LP Interest 7.5% LP Interest 47.0% LP Interest Höegh LNG Holdings & Affiliated Unitholders2 Institutional Holders of HMLP Common Units Retail / Other Common Unitholders Source: FactSet (as of 5/23/22), Partnership materials Note: Unit price of $6.86 as of 5/23/22; Ownership Structure does not sum to 100% due to Stohle Sveinung J S insider ownership position of less than 1% 1. Does not include full value of G.P. interest or value of IDRs 2. Includes units owned by Sponsor and Morten W. Höegh, an affiliated unitholder in the Proposed Transaction Unaffiliated Unitholders ($ in thousands) 4 |
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Preliminary Draft – Confidential Introduction Key Partnership Issues for Consideration Source: Partnership Management, Partnership materials PGN and its now parent company, Pertamina, filed a notice of arbitration against HMLP in August 2021, which sought to nullify the charter currently in-place with HMLP for use of the Lampung FSRU f The Lampung is currently chartered out with PGN through October 2034 at a capex rate of $ and is fitted with specialized equipment that allow it to connect to its terminal in Indonesia f Upon commencing the dispute in August 2021, PGN was dissatisfied with the contract While the Partnership has received two legal opinions from Indonesian experts However, since the start of the PGN dispute, the market has improved and PGN may have less incentive to pursue the arbitration due to the tight market for alternative FSRUs and current FSRU rates PGN Dispute 6 Less Alignment with Sponsor While the $12.00 New Fortress Energy (NFE) indication for all outstanding LP units (including Sponsor-affiliated units) in a control transaction represents incremental value versus the $9.25 offer from the Sponsor, the Committee did not view it as a viable alternative f In its original NBO for the units, the Sponsor stated it would not consider any third-party offer for the unaffiliated units outstanding; upon receipt of the NFE indication, the Sponsor and its advisors reiterated to the Committee and its advisors that it would not consider NFE’s proposal or any other proposal for sale of its units f The NFE indication was non-binding and subject to diligence, which could have materially altered perceived value When HLNG was taken private in March 2021, some provisions of the Omnibus Agreement between HMLP and the Sponsor were terminated, allowing HLNG to formally compete with HMLP In tandem with the onset of the Lampung arbitration, the Sponsor announced it would not extend the $85mm internal RCF to the Partnership, thus limiting liquidity and risking the Partnership’s cash flows Furthermore, the Sponsor has stated that given the Partnership’s cost of equity, the Sponsor would be unlikely to provide dropdown transactions to HMLP, thus limiting future growth prospects New Fortress Energy Indication of Interest |
Preliminary Draft – Confidential II. Overview of Evercore Process |
Preliminary Draft – Confidential Overview of Evercore Process In connection with our evaluation, Evercore has, among other things: i. Reviewed certain publicly available business and financial information relating to HMLP that we deemed to be relevant, including publicly available research analysts’ estimates ii. Reviewed certain internal projected financial data relating to HMLP, reflecting seven management cases (the “Management Cases”), in each case prepared and furnished to us by management of the MLP as approved for our use by the Conflicts Committee (the “Management Projections”); iii. Reviewed certain third-party charter free vessel appraisals of the vessels of HMLP furnished to us by management of HMLP as approved for our use by the Conflicts Committee (the “Appraisals”); iv. Reviewed certain reports prepared for the Conflicts Committee by Poten & Partners Inc.; v. Discussed with the Conflicts Committee and management of HMLP their assessment of the past and current operations of HMLP, the current financial condition and prospects of HMLP, and the Forecasts under each of the Management Cases; vi. Reviewed the reported prices and the historical trading activity of the Common Units; vii. Compared the financial performance of HMLP and its stock market trading multiples with those of certain other publicly traded master limited partnerships and other companies that we deemed relevant; viii. Compared the financial performance of HMLP and the valuation multiples relating to the Merger with the financial terms, to the extent publicly available, of certain other transactions that we deemed relevant; ix. Reviewed the financial terms and conditions of a draft, dated [●], 2022, of the Merger Agreement; and x. Performed such other analyses and examinations and considered such other factors that we deemed appropriate. Evercore Evaluation Process 7 |
Preliminary Draft – Confidential Overview of Evercore Process Evercore Evaluation Process: Selected Provisions For purposes of our analysis and opinion, we have assumed and relied upon the accuracy and completeness of the financial and other information publicly available, and all of the information supplied or otherwise made available to, discussed with, or reviewed by us, without any independent verification of such information (and have not assumed responsibility or liability for any independent verification of such information), and have further relied upon the assurances of the management of the MLP that they are not aware of any facts or circumstances that would make such information inaccurate or misleading. With respect to the Forecasts, we have assumed with your consent that they have been reasonably prepared on bases reflecting the best currently available estimates and good faith judgments of management of the MLP as to the future financial performance of the MLP under each of the Management Cases, as applicable, and that each of the Management Cases reflects the good faith judgment of management as to a reasonably likely alternative with respect to the maters reflected therein. We express no view as to the Forecasts or the Appraisals, or the assumptions on which they are based, as applicable, including the assumptions reflected in the Management Cases. We have relied, at your direction, without independent verification, upon the assessments of the management of the MLP as to the future operational performance of the MLP, including but not limited to, charter revenues, commissions, operating expenses, administrative expenses and other fees and expenses. For purposes of our analysis and opinion, we have assumed, in all respects material to our analysis, that the final executed Merger Agreement will not differ from the draft Merger Agreement reviewed by us, that the representations and warranties of each party contained in the Merger Agreement are true and correct, that each party will perform all of the covenants and agreements required to be performed by it under the Merger Agreement and that all conditions to the consummation of the Merger will be satisfied without waiver or modification thereof. We have further assumed, in all respects material to our analysis, that all governmental, regulatory or other consents, approvals or releases necessary for the consummation of the Merger will be obtained without any delay, limitation, restriction or condition that would have an adverse effect on the MLP or the consummation of the Merger or reduce the contemplated benefits to the holders of Common Units of the Merger. We have not been asked to pass upon, and express no opinion with respect to, any matter other than the fairness to the holders of the Common Units (other than the Sponsor Entities and their affiliates), from a financial point of view, of the Merger Consideration. We do not express any view on, and our opinion does not address, the fairness of the proposed transaction to, or any consideration received in connection therewith by, the holders of any other class of securities, creditors or other constituencies of the MLP, nor as to the fairness of the amount or nature of any compensation to be paid or payable to any of the officers, directors or employees of the MLP, or any class of such persons, whether relative to the Merger Consideration or otherwise. 8 |
Preliminary Draft – Confidential III. Situation Overview |
Preliminary Draft – Confidential Situation Overview Summary Market Data Public Market Overview Capital Structure ($ in millions, except per unit data) 9 As of 5/23/22 HMLP Common Unit Price (5/23/22) $6.86 52-Week High 18.17 52-Week Low 3.77 Partnership Common Units Outstanding 33.373 Equity Value $228.9 (+) Preferred Equity as of 5/23/22 171.8 (+) Total Debt Outstanding as of 3/31/22 396.8 (–) Accumulated Profits of JVs as of 3/31/22 (47.6) (–) Cash and Cash Equivalents as of 3/31/22 (56.2) Enterprise Value $693.7 Trading Multiples Metric Multiple FactSet Mgmt FactSet Mgmt EV / EBITDA 2022E $115.2 $107.8 6.0x 6.4x 2023E 120.5 107.6 5.8 6.4 Distribution Yields 2022E $0.04 0.6% 2023E 0.04 0.6% Metric Multiple P / NAV2 $386.5 0.59x As of 3/31/22 Total Debt $396.8 (–) Cash and Equivalents (56.2) Net Debt $340.6 Book Value of Common Equity $389.1 Book Value of Preferred Equity 176.1 Enterprise Value (Book Value) $905.8 Net Debt / Enterprise Value (Book Value)3 37.6% Net Debt / 2022E EBITDA3 4.7x Net Debt / 2023E EBITDA3 4.7 Gross Charter-Free LTV3,4,5 69.1% Net Charter-Free LTV3,4,5 63.8% Debt Details Facility Balance Maturity Parent RCF $24.5 1/1/23 385 RCF 63.1 1/30/26 PGN FSRU Lampung 71.2 10/31/21 - 10/31/26 Höegh Gallant and Höegh Grace 243.2 1/30/26 - 7/30/28 Amortizing Debt Issuance Cost (5.1) Total Debt $396.8 JV Debt Details Facility Balance Maturity Neptune (50% Ownership) $82.2 11/30/21 - 10/31/29 GDF Suez Cape Ann (50% Ownership) 87.4 6/1/22 - 4/30/30 Total JV Debt $169.6 Source: Management Projections, Partnership materials, FactSet (as of 5/23/22) Note: Balance sheet figures represent draft Q1 2022 figures provided by Partnership Management on 5/23/22 1. Preferred equity value is based on 7.089mm outstanding units at a price of $24.23 (as of 5/23/22) 2. Based on Evercore’s NAV analysis contained herein. Assumes charter-free appraised values indicated in Fearnleys and Braemar appraisal reports dated May 2022, as provided by Partnership Management. Neptune and Cape Ann asset values adjusted for 50% ownership 3. Calculated as gross (net) debt divided by the sum of the Lampung, Gallant, Grace and 50% of the Neptune and Cape Ann average charter-free appraisal values; debt values inclusive of 50% proportional JV debt 4. Figures exclude share of results of joint ventures 1 |
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Preliminary Draft – Confidential Year Age Capacity Ownership Earliest Charter Rate Charter-Free Appraised Value (May '22) Vessel Name Delivered (Years) (cbm) (%) Charter Expiry (USD / Day) Fearnleys Braemar Av e r age FSRU Vessels Neptune 2009 12.5 145,000 50% 11/30/29 $ $190 $205 $198 Cape Ann 2010 12.0 145,000 50% 6/1/30 184 200 192 PGN FSRU Lampung 2014 8.1 170,000 100% 10/31/34 265 300 283 Höegh Gallant 2014 7.6 170,000 100% 12/1/31 275 300 288 Höegh Grace 2016 6.2 170,000 100% 12/31/26 282 325 304 Total Value $1,196 $1,330 $1,263 Weighted Average Age (Years) 8.8 Situation Overview Detailed Fleet Overview Source: Partnership materials Note: JV vessel figures shown on a 100% consolidated basis 1. Inclusive of $ capex, $ opex and $ tax element rates per day 2. Inclusive of $ capex, $ opex and $ tax element rates per day 3. Inclusive of $ capex, $ opex and $ tax element rates per day 4. Inclusive of $ capex, $ opex, $ tax element rates per day and $ per day make-whole payment from the Sponsor, which ends in August 2025 5. Inclusive of $ capex, $ opex and $ tax element rates 6. Total value is shown on a 100% consolidated basis regarding JV vessels 7. As of 5/23/2022. Weighted by average charter free asset value ($ in millions, except per day data) 1 2 3 4 5 7 6 JV Vessels 12 |
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Preliminary Draft – Confidential Situation Overview Charter Profile Vessel Counterparty CapEx Rate1 Opex Rate1 Gross Charter Rate1 Initial Charter Duration (Years) Neptune TGPL $ $ $ Cape Ann TGPL PGN FSRU Lampung PGN Höegh Gallant NFE Höegh Grace SPEC 7.5 8.0 12.4 9.5 4.6 - 3.0 6.0 9.0 12.0 15.0 Weighted average4 remaining initial charter duration of 8.4 years (assumes extension options not exercised) Source: Partnership materials Note: JV vessel figures shown on a 100% consolidated basis 1. Based on initial charter 2. Lampung and Grace figures include tax element rates of $ and $ per day, respectively 3. Includes $ per day make-whole payment from the Sponsor, which ends in August 2025 4. Weighted based on gross charter rate. Extension options not included as they are assumed not to be exercised in management analysis 2 2 13 3 |
Preliminary Draft – Confidential Fleet Three fully-owned vessels Two 50% ownership joint venture vessels Assumed useful life of 35-years per vessel Utilization Utilization based on drydock and offhire schedules Drydock assumed in five year increments for each vessel Offhire assumed as 20 days, except for Lampung and Grace, which are assumed as 24 and 30 days, respectively Charter Schedule Assumes that ships roll to subsequent time charter contracts following the completion of scheduled charter expiration1 Expenses / Costs Direct expenses, corporate G&A, dry docking expense and baseline vessel opex assumed to grow at 5.0% inflation over 2023 and 2024 and 2.0% thereafter Assumes the below annual corporate level expenses2: Scrap Value Assumes the below scrap values and scrap dates: Situation Overview Key Management Projections Assumptions 14 Source: Management Projections 1. PGN FSRU Lampung sensitized across cases which consider the early termination of its current charter 2. Figures in 2022 nominal values Ve sse l Scrap Value Scrap Date PGN FSRU Lampung $13.5 4/22/49 Höegh Gallant 13.5 11/4/49 Höegh Grace 13.5 3/29/51 Neptune 12.1 11/30/44 Cape Ann 12.1 6/1/45 ($ in millions, except per day data) Ve sse l Income Tax Withholding Tax G&A Expenses PGN FSRU Lampung $6.4 $1.6 Höegh Gallant 0.2 0.1 Höegh Grace 2.6 0.3 Total $9.2 $2.0 $7.2 |
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Preliminary Draft – Confidential Situation Overview Key Management Projections Assumptions (Cont’d) 15 1. Financial model provided by Partnership Management on 4/8/22 assumed $35mm in capacity upgrade costs, which was subsequently revised to a midpoint $75mm estimate 2. Financial model provided by Partnership Management on 4/8/22 assumed 2 month idle period for capacity upgrade in Case 7, which was subsequently revised to a 4 month estimate 3. Gallant assumed to receive additional make-whole payment of $ per day from the Sponsor until August 2025 PGN FSRU Lampung by Case Item Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 7 Annual PGN Arbitration Costs ($mm) $4.0 $4.0 $4.0 $4.0 $4.0 $4.0 $4.0 Arbitration & Arbitration Costs End Date 10/31/22 10/31/22 10/31/22 10/31/22 10/31/22 12/31/23 12/31/23 Capacity Upgrade Termination / Sale Proceeds ($mm) $ $ $ $ $ Capacity Upgrade Costs ($mm) 75.0 75.0 75.0 75.0 First Recharter Capex Rate ($k/d) $ $ $ $ $ $ Recharter Subsequent Recharter Capex Rate ($k/d) Assumptions Opex Rate ($k/d) Opex Cost ($k/d) Annual Comissions Expense ($mm) 1.5 1.5 0.8 0.8 0.8 0.8 All Other Vessels Item Current Contract Idle Assumption Long-Term Assumption Capex Rate ($k/d) $ $ $ Opex Rate ($k/d) Höegh Gallant Tax Element ($k/d) Opex Cost ($k/d) Annual Commissions Expense ($mm) 0.2 0.0 0.8 Capex Rate ($k/d) $ $ $ Opex Rate ($k/d) Höegh Grace Tax Element ($k/d) Opex Cost ($k/d) Annual Commissions Expense ($mm) 0.8 0.0 0.8 Capex Rate ($k/d) $ $ $ Opex Rate ($k/d) Neptune Tax Element ($k/d) Opex Cost ($k/d) Annual Commissions Expense ($mm) 0.8 0.0 0.8 Capex Rate ($k/d) $ $ $ Opex Rate ($k/d) Cape Ann Tax Element ($k/d) Opex Cost ($k/d) Annual Commissions Expense ($mm) 0.8 0.0 0.8 3 Summary of Key Assumptions by Vessel 1,2 Source: Management Projections Note: Figures in 2022 nominal values |
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Preliminary Draft – Confidential Situation Overview 16 Source: Management Projections Key Management Projections Assumptions – Sensitivity Cases on the Lampung Case 1 PGN contract is amended starting in November 2022 f Capex rate is reduced from $ to $ f Contract length is extended 5 years f Vessel ownership is transferred to PGN at the end of the contract (Nov. 2039) for $ Lampung debt continues as is; no change in distribution to unitholders Case 2 PGN contract is amended starting in November 2022 f Capex rate is reduced from $ to $ f Contract length is extended 5 years f Vessel ownership is transferred to PGN at the end of the contract (Nov. 2039) for $ Lampung debt continues as is; no change in distribution to unitholders Case 3 PGN buys the vessel for $ in November 2022 and the contract terminates HMLP repays Lampung debt and redeems all preferred units at par HMLP repays the drawn amount under the external RCF Case 4 PGN pays $ to HMLP to terminate the contract in November 2022 Lampung is idle for 18 months - upgraded for $75mm and incurs opex while idle Redeployed at a capex rate of $ , and operated for remaining useful life. Assumes 10 year contract duration for new employment and 9 months idle time between each renewal with $5mm class renewal cost Case 5 PGN pays $ to HMLP to terminate the contract in November 2022 Lampung is idle for 18 months - upgraded for $75mm and incurs opex while idle Redeployed at a capex rate of $ , and operated for remaining useful life. Assumes 10 year contract duration for new employment and 9 months idle time between each renewal with $5mm class renewal cost Distribution suspended for common and preferred units over 2023 and thereafter reinstated at same level as today Case 6 PGN wins arbitration and the contract is terminated in January 2024 without any compensation Lampung is idle for 18 months - upgraded for $75mm and incurs opex while idle Redeployed at a capex rate of $ , and operated for remaining useful life. Assumes 10 year contract duration for new employment and 9 months idle time between each renewal with $5mm class renewal cost Distribution suspended for common and preferred units between Q1 2025 and Q4 2027 and thereafter reinstated at same level as today Case 7 PGN contract remains in place through 2034, the vessel is then upgraded for $75mm assumed idle for four months. Vessel incurs opex while idle Redeployed at a capex rate of $ , and operated for remaining useful life. Assumes 10 year contract duration for new employment and 9 months idle time between each renewal with $5mm class renewal cost |
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CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
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Preliminary Draft – Confidential IV. Valuation of the Common Units |
Preliminary Draft – Confidential Valuation of the Common Units Methodology Description Assumptions and Sources Charter Free Net Asset Values1 Reviewed the desktop appraisals for HMLP’s FSRUs, which represents the estimated price at which the asset would change hands between willing buyer and seller, with neither under compulsion to buy or sell, with both having full knowledge of relevant facts Adjusted to incorporate value of relevant assets and liabilities in the business, including working capital, cash, debt and other debt-like items, to calculate NAV per unit Fleet appraised values are based on the average of Fearnleys appraisals (5/10/22) and Braemar appraisals (5/11/22), adjusted for 50% ownership in the Neptune and Cape Ann Cash, working capital and debt outstanding based on draft Q1 2022 figures provided by Partnership Management on 5/23/22 Preferred equity based on market value as of 5/23/22 Useful Life Discounted Cash Flow2 Fixed portfolio of ships for the balance of the vessels’ useful life Values the asset using the concept of time value of money All future cash flows (based on the remaining useful life) reflect management estimates and discounted to their present values Vessels assumed to have a useful life of 35 years Assumptions regarding charter rates, opex, corporate and other costs, recharter assumptions, scrap assumptions, and alternative scenarios regarding the treatment of the Lampung are in accordance with management guidance, as outlined on pages 14- 16 Future cash flows discounted at a WACC range of 8.0% to 9.0% Recharter capex rates sensitized at +/- 5.0% Peer Trading Analysis Values the Common Units based on current enterprise value multiples of relevant EBITDA metrics and price to net asset value (NAV) Public market companies: Capital Product Partners LP, Dynagas LNG Partners LP, Excelerate Energy, Flex LNG, Gaslog Partners LP and KNOT Offshore Partners LP Enterprise value / EBITDA multiples applied to 2022E and 2023E EBITDA Public market companies Price / Net Asset Value per Unit is based on recent broker NAV estimates from Pareto and Jefferies research reports. HMLP based on analysis herein Precedent Transactions Valuation based on multiples of transaction value to last-twelve-months EBITDA of similar LNG-related transactions Limited number of similar precedent LNG-related transactions Other relevant shipping transactions also evaluated as reference point for EBITDA multiples applied 1. Due to the significant volatility in charter rates in the current market environment, charter free asset values have been used for this analysis 2. With the consent of the Committee, Evercore did not utilize a Corporate DCF to analyze the value of the common units as the Sponsor indicated it would be unlikely to provide dropdown transactions to HMLP, thus limiting future growth prospects and making a useful life discounted cash flow analysis derived from our current vessel portfolio through their useful lives the most relevant measure of cash flow 24 Overview of Selected Valuation Methodologies Evercore utilized Management Projections and the following methodologies to analyze the value of the Common Units: Note: This summary of certain analyses is provided for illustrative purposes. It does not represent all of the analyses performed by Evercore and should be considered with the information elsewhere in this presentation. |
Preliminary Draft – Confidential NAV Useful Life DCF Peer Trading Precedents Appraised Asset Value Sensitivity: ± 5.0% Based on High and Low Midpoint DCF Values Across Management Cases TEV / LTM EBITDA 52-Week Common Unit Price Range Premiums Paid Based on 25th and 75th percentile of the One-Day, One-Week and One-Month Premiums Paid Management Cases Equity Research Price Targets 2 Charter Free Net Asset Value1 EV / 2022E EBITDA EV / 2023E EBITDA Price / NAV 2022E EBITDA Multiple: 7.0x – 9.0x 2023E EBITDA Multiple: 6.5x – 8.5x Price / NAV Multiple: 0.70x – 1.05x LTM EBITDA Multiple: 7.0x – 10.5x Based on Low and High Equity Research Price Targets $9.98 $3.49 $8.69 $7.03 $8.11 $7.05 $3.77 $4.68 $5.00 $13.18 $9.98 $15.15 $13.47 $12.16 $17.54 $8.17 $6.10 $9.50 $11.58 $6.73 $11.92 $10.25 $10.13 $12.29 $ - $5.00 $10.00 $15.00 $20.00 $18.17 Unit price as of 5/23/22: $6.86 Merger Consideration: $9.25 Valuation of the Common Units Summary Valuation of the Common Units 25 For Reference Only 52-week Range Range since distribution cut3 Source: Partnership Management, Management Projections, FactSet (as of 5/23/22), Duff & Phelps 2022 Valuation Handbook, Wall Street research. | Note: This summary of certain analyses is provided for illustrative purposes. It does not represent all of the analyses performed by Evercore and should be considered with the information elsewhere in this presentation. Due to the volatility in charter rates in the current market environment, charter free asset values are more reliable than charter attached asset values for the purposes of this analysis. As compared with the draft of the materials presented to the Committee on May 16, 2022, the useful life discounted cash flow analysis shown herein does not consider the illustrative $4mm of annual G&A synergies the Partnership may be able to achieve from a take-private transaction. As is customary in similar transactions, the valuation analysis contained herein assesses the Partnership on a standalone basis. The previously considered $4mm in annual synergies represents $1.32 per unit of value at a discount rate of 8.50%. 1. Due to the significant volatility in charter rates in the current market environment, charter free asset values have been used for this analysis 2. Price target estimates include B Riley estimate of $5.00 as of 11/19/21 (subsequent $4.25 price target predicated on the offer price being accepted) and Stifel estimate of $9.50 as of 3/28/22 3. On July 27, 2021 HMLP announced a reduction in the quarterly cash distribution per common unit from $0.44 to $0.01 |
Preliminary Draft – Confidential Valuation of the Common Units Useful Life Discounted Cash Flow Analysis by Case 28 Source: Management Projections, FactSet (as of 5/23/22), Duff & Phelps 2022 Valuation Handbook, Wall Street research Note: Indicated valuation ranges based on sensitivity analysis assuming WACC of 8.00% to 9.00% and assuming midpoint recharter capex rates sensitized by ± 5.0%. As compared with the draft of the materials presented to the Committee on May 16, 2022, the useful life discounted cash flow analysis shown herein does not consider the illustrative $4mm of annual G&A synergies the Partnership may be able to achieve from a take-private transaction. As is customary in similar transactions, the valuation analysis contained herein assesses the Partnership on a standalone basis. The previously considered $4mm in annual synergies represents $1.32 per unit of value at a discount rate of 8.50%. Partnership Management Cases Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 7 $7.26 $6.39 $8.89 $5.69 $4.01 $2.05 $7.88 $9.92 $9.01 $11.18 $8.81 $7.12 $5.07 $10.77 $8.53 $7.64 $9.98 $7.18 $5.49 $3.49 $9.25 $ - $3.00 $6.00 $9.00 $12.00 |
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CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
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Preliminary Draft – Confidential Appendix |
Preliminary Draft – Confidential Excelerate Energy – Broker Growth Estimates Source: FactSet (as of 5/23/22) 42 ($ in millions, except per share data) Broker Forecasted EBITDA Broker Forecasted Dividends per Share $0.08 $0.11 $0.13 $0.24 2022E 2023E 2024E 2025E $262 $308 $339 $502 2022E 2023E 2024E 2025E 24.1% CAGR 41.5% CAGR |
Exhibit (c)(8)
EXPERT ADVISORS TO THE LNG AND NATURAL GAS INDUSTRIES www.poten.com |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Provide a high-level description of the FSRU market through 2035. This assessment will consider, to the extent feasible, the impact on the FSRU market of the Russian/Ukraine conflict and the requirement to reduce European dependency on Russian pipeline gas. The description will include our base, high and low forecast of the number of FSRUs that are likely to be employed worldwide and the type of projects in which they are likely to be employed. • Identify the segments of the FSRU market in which Höegh MLP is likely to compete and make a high-level assessment of the competitors that Höegh MLP is likely to face in seeking to secure new projects. We will provide base, high and low forecasts through 2035 of the number of additional FSRU projects that Höegh MLP could secure. • Provide base, high and low forecasts of annual FSRU charter rates for new vessels through 2035 based on our LNG supply and demand forecasts, scenarios for FSRU, FSU and LNG carrier requirements and drivers. • Provide base, high and low annual forecasts of long-term rechartering rates to 2035 for Höegh MLP’s current fleet for service as FSRUs and will provide a perspective on range of length of time expected to recharter an FSRU. We will analyze and explain the difference for divergence between these rechartering rate forecasts and the forecasted charter rates for new FSRUs per item 3 above. • Poten will comment on the technical feasibility of using the FSRUs in Höegh MLP’s current fleet as LNG carriers. Poten will provide base, high and low forecasted annual charter rates to 2035, taking into account the technical specifications of Höegh MLP’s assets, if they are so used as LNG carriers. • Poten will review and comment on the relevant assumptions in financial forecasts provided by management of Höegh MLP. • Poten will share views on how LNG carrier conversions to FSRUs will impact the supply / demand balance and resultant charter rates through 2035. • To the extent it is not covered in the preceding categories, Poten will provide estimated recharter rate, contract period and idle time for the FSRU Lampung in the event PGN were to terminate the contract today. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Lampung FSRU • Cape Ann • Neptune • Höegh Grace • Höegh Gallant • Neptune is suitably equipped and able to be used as an FSRU • Each vessel is also addressed in separate sections of the report |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • These include FSRU rates and employment prospects after the termination of current contracts. • Neither of these documents appears to include any impact of EEXI/CII requirements post 1/1/2023 |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • However, X-DF and ME-GI are not propulsion systems used for FSRUs • DFDE/TFDE remain the propulsion system of choice for FSRUs due to their flexibility in meeting varying power demands associated with varying send-out rates. • A significant proportion of the existing LNGC fleet has similar boil off rates of 0.12% – 0.15% • The FSRU and LNGC markets are segmented with different rates applying based on size, propulsion and spec. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • All but three of the newbuilds are aged 15 years or less. Most vessels aged 15+ are conversions. • Around half of the newbuilds are 5 years old or less. • However, one vessel - LNG Vesta - is currently mooted for FSRU conversion by KARMOL. • Built 1994, 127,547m3 capacity. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Cape Ann/Neptune lightweight at 31,676mt • Höegh Grace/Gallant lightweight at about 34,755mt • Lampung lightweight at about 33,957mt • Could reduce lead time for certain cryogenic equipment |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Steam turbine vessels make up 36% of the existing LNGC fleet • D/TFDE vessels account for 30% of the LNGC fleet • HMLP does not operate any steam turbine vessels • Speeds will be reduced (12 knots loaded, slower ballast speed?) or speed matched to boil off • Some vessels may become uneconomic to operate • Charterers likely to avoid STs based on lower CII ratings • Winter spot charter rates and term charter rates may be significantly higher, summer charter rates higher if STs are idled and available capacity cut • New builds unable to meet demand in short term |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL PGN FSRU Lampung is moored off southern Sumatra using a soft yoke tower mooring which connects the FSRU to a tower mounted on the seabed and permitting 360 degrees rotation of the FSRU so that it can always align with the prevailing metocean conditions. There are no limiting operational metocean conditions identified for send-out and the vicinity where it is moored is reasonably benign. Lampung FSRU send-out capacity is relatively low (360 mmscf/d) compared with many FSRUs which are typically in the 500 – 750 mmscf/d range, but a number have send-out capacities <400 mmscf/d. LampungL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Memoranda are notes pertaining to the vessel and can be removed when any conditions are complied with, or the memorandum is not longer valid. • Conditions of Class normally relate to damage or other matters that needs to be repaired or addressed within a stated period of time |
© POTEN & PARTNERS 2009 CONFIDENTIAL ARTNERS 2 2 2 2 2009 TI I I IAL AL AL AL AL |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Engine is for propulsion to site only • A conventional FSRU capable of trading as an LNGC will have a manifold configuration of L-L-V-L-L to enable multiple loading arms to be connected. • A conventional FSRU capable of trading as an LNGC will normally have a loading rate in excess of 10,000m3/hr, and accept LNG in a STS operation at a transfer rate of 6,000 -8,000m3/hr dependent on vapor management • Normal laytime allowed for LNG loading or discharge is 36 hours. • A conventional FSRU capable of trading as an LNGC will typically have 2 cargo pumps per tank with capacities each in excess of 1,500m3/hr |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Limits options for future use and locations • Send out typically >500mmscf/d required in most locations, but may not always be fully utilized |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Hoegh have estimated $35 million and at least 2 months for this work. • Poten considers that the amount budgeted and time allowed is insufficient for the work that needs to be undertaken and suggests closer to $45 million and more likely 3-4 months • Additional manifold arrangements and increase in load/discharge rates would also be required to trade. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Modifications would most likely not be required – similar level of usage as today • Mooring configuration has to be considered – water depth about 45m |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Memoranda are notes pertaining to the vessel and can be removed when any conditions are complied with, or the memorandum is not longer valid. • Conditions of Class normally relate to damage or other matters that needs to be repaired or addressed within a stated period of time |
© POTEN & PARTNERS 2009
CONFIDENTIAL
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A A A A ART R RT RT RTNE N N N N
TI I I I IAL AL AL AL AL
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© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL x x x x x x |
© POTEN & PARTNERS 2009 CONFIDENTIAL • This is lower than is typically the case for LNGCs (10, 12 or even 14,000m3/hr) • Typically, bulk discharge time is closer to 12 hours • An LNGC built at a similar time to Hoegh Grace will typically have main cargo pumps with a rated capacity in excess of 1,500m3/hr (more typically around 1,750m3/hr each) • In future, as carbon dioxide emissions reporting becomes significant, the service speed is unlikely to be an important consideration. |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • However, the vessel is known to have experienced a technical problem with a cargo pump at the Futtsu LNG terminal in Japan in 1Q 2020 which resulted in a penalty of $11.016.75 from a 3.97 hour delay in discharge time. |
© POTEN & PARTNERS 2009 CONFIDENTIAL x x x x x x |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • This is lower than is typically the case for LNGCs (10, 12 or even 14,000m3/hr) • Typically, bulk discharge time is closer to 12 hours • An LNGC built at a similar time to Hoegh Grace will typically have main cargo pumps with a rated capacity in excess of 1,500m3/hr (more typically around 1,750m3/hr each) • In future, as carbon dioxide emissions reporting becomes significant, the service speed is unlikely to be an important consideration. |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Operated in this mode, the vessels require dry docking on a regular basis • The STL connection arrangement offers a significantly cheaper mooring solution in exposed locations or water depths of greater than about 35m • The vessels have dynamic positioning capability for use with picking up an STL connection in open water. ARTNERS 2 2 2 2 2009 TI TI I I IAL AL AL AL AL |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL x x x x x |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL 1 Ballast engine room tank port 2 Ballast engine room tank starboard 3 Aft peak tank 4 Double bottom/side tank 1P, 1S, 2P, 2S, 3P |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL ° • Vessel is only able to operate in closed loop heating system – suitable for cold water locations but consumes more fuel for cargo heating • When operating in N+1 configuration, send-out rate is 500mmscf/d |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • The vessel has loaded at Idku in Egypt and discharged at Revithoussa in Greece. Currently at anchor outside port limits Malta after loading at Idku |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL x Midships draft not to exceed 12.4m x Minimum forward draft of 8.64m without limitation on ballast tank filling x If forward draft is <8.64m, vessel to take precautions to avoid slamming x Cargo tank filling limits not to be between 2.75m to 70% tank height in open water (Poten note - to minimize risk of sloshing damage to tanks) x Maximum allowable relief valve setting is 0.25 Bar x If cargo tanks 2-4 are empty, ballast level in ballast tanks must be to at least the level of the inner bottom x |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • 3 months engineering and design work necessary to identify requirements • Cryogenic equipment lead times could be 15-18 months - Based on number of LNGCs under construction, overhang of shipyard orders and reduction in nickel availability from Russia • Conversion time of 3 months – extent of conversion and work required will depend on specification, LNG heating requirements and any other work such as replacement of obsolete/soon to be obsolete equipment (eg IAS, F&GD) • Mobilization to site • Upgrades will add more to the conversion cost • Loading LNG on mobilization voyage for commissioning terminal can advance charter income • Also eliminates gas up/cool down time/cost and STS transfer on arrival at site before commissioning |
© POTEN & PARTNERS 2009 CONFIDENTIAL • The older the vessel, the higher the conversion costs, but cheaper the purchase price • End up with limited LNG capacity against current parcel sizes and major “surgery” required to convert and upgrade • Significant upgrades required in auxiliary systems – sewage systems, air conditioning, incineration, utilities, etc. |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Whether this time scale is still applicable to these projects if LNG prices increase significantly on supply shortages remains to be seen • Further accentuated by the cut in pipeline gas supplies to Bulgaria and Poland |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Only suitable for warm seawater conditions and has low send-out rate • Would require significant increase in regas capacity, LNG receiving rate, additional HP manifold for alongside mooring and full dry docking • Yard time minimum 2 months (more likely 3 months) • Positioning voyage to Europe (basis Malta, mid Mediterranean) would take 27 days at 10 knots (via Suez). ö ö |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Germany 3, Italy 2, France 1, Poland 1, Estonia 1 and Latvia 1 • Estonia is discussing “”sharing” an FSRU with Finland • Turkey and Greece may also need additional FSRUs • UK may need to reinstate the Teesport FSRU facility • 3 FSRUs known to have been taken, plus a regas barge – Golar Tundra purchased for use in Italy – Other FSRU charters being worked – Some charters apparently have potential break options at 5 years (with a penalty) • Newbuilds would take too long to come to market A A A ART RT RTNE NE NE N NERS S S S S 2 2 2 200 00 00 00 0 9 9 9 9 9 • Replacement vessels/cheaper charter rates may not be an option |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Permitting • Environmental restrictions • Equipment availability • EPC/Construction supervision (multiple construction projects in parallel) • Funding – shareholder criticism of financial institutions’ lending for oil and gas projects |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • If the dry dockings of these vessels is protracted, or there is any significant increase in dry dock scope or costs, Hoegh will be exposed to increased loss of hire and these increased costs. |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL N&PA RT T T TN N NE N N RS 2009 N N N & & & & & PA PA PA PA PART RT RT RT RTNE N NE NE NERS RS RS RS RS 2 2 2 2 20 ID D D DEN EN EN ENTI TI TI T AL AL AL AL AL |
Exhibit (c)(9)
CONFIDENTIAL TREATMENT REQUESTED
© POTEN & PARTNERS 2009 CONFIDENTIAL |
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
© POTEN & PARTNERS 2009 CONFIDENTIAL • Uniper have chartered 2 FSRUs at a reported $ - $ /day for 10 years • RWE has chartered an FSRU at $ /day • Snam has acquired an FSRU for an undisclosed amount (HMLP indicates $ ) • HMLP suggests the capex rates are closer to $ /day ARTNERS 2009 TIAL AL AL AL AL |
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
© POTEN & PARTNERS 2009 CONFIDENTIAL |
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
© POTEN & PARTNERS 2009 CONFIDENTIAL |
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
© POTEN & PARTNERS 2009 CONFIDENTIAL |
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
© POTEN & PARTNERS 2009 CONFIDENTIAL • Vessel is idle for 18 months and is upgraded at a cost of $35 million to increase send-out capacity. Opex incurred during idle time. • Vessel is redeployed at capex rate of $ /day. 10 year contract duration each time, 9 months idle between contracts and $5m class renewal costs every 5th year. Vessel is scrapped at 35 years of age. • Design work may be contingent on proposed location for the next assignment, not simply upgrade to send-out capacity. • Opex can be reduced/minimized with vessel in semi-layup. TIAL AL AL AL A |
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
© POTEN & PARTNERS 2009 CONFIDENTIAL • Vessel is idle for 18 months and is upgraded at a cost of $35 million to increase send-out capacity. • Opex incurred during idle time. • Vessel is redeployed at capex rate of $ /day. 10 year contract duration each time, 9 months idle between contracts and $5m class renewal costs every 5th year. Vessel is scrapped at 35 years of age. • Opex can be reduced/minimized with vessel in semi-layup. A A A A ART RT RT RT RTNE E ERS RS RS RS R 200 00 00 00 009 9 9 9 TIAL |
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
© POTEN & PARTNERS 2009 CONFIDENTIAL • Vessel is idle for 18 months and is upgraded at a cost of $35 million to increase send-out capacity. • Opex incurred while idle. • Vessel is redeployed at capex rate of $ day. 10 year contract duration each time, 9 months idle between contracts and $5m class renewal costs every 5th year. • Vessel is scrapped at 35 years of age. • Opex can be reduced/minimized with vessel in semi-layup. A A A A ART RT RT RT RTNE E ERS RS RS RS RS 200 00 00 00 009 9 9 9 TIAL |
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
© POTEN & PARTNERS 2009 CONFIDENTIAL • When the contract expires in 2034, vessel is upgraded for $35m and idle for 2 months. Opex incurred during this period. • Vessel is redeployed at capex rate of $ day. 10 year contract duration each time, 9 months idle between contracts and $5m class renewal costs every 5th year. Vessel is scrapped at 35 years of age. • Opex can be reduced/minimized with vessel in semi-layup. |
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
© POTEN & PARTNERS 2009 CONFIDENTIAL • In the case of status quo, there may be some adjustment of capex rate • Change in charterer’s market fundamentals is not normally a basis for termination unless it falls in a force majeure category. However, that could be tempered by lack of trading capacity as an LNGC • Charterer may have other opportunities to use FSRU elsewhere in Indonesia which might limit PGN losses |
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
© POTEN & PARTNERS 2009 CONFIDENTIAL • From a positive perspective, and unlike PGN FSRU Lampung, these vessels can be operated as LNGCs if required • On this basis, a reduction to $ /day could be considered reasonable. • Having initiated termination arbitration, extension, even at a lower rate, will most likely be considered unacceptable by the charterer. |
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
© POTEN & PARTNERS 2009 CONFIDENTIAL • It is assumed that this termination value would be the discounted value of future hire payments. • PGN would not have other FSRU options available in the market • Any replacement vessel will require substantial modification to suit the Tower Yoke mooring structure • Engineering studies should be carried out now, in advance of arbitration decision, to avoid any loss of time when decision is announced • HMLP may need to bear additional costs and off-hire associated with this option |
© POTEN & PARTNERS 2009 CONFIDENTIAL • The initial estimate was $35 million and about 2 months to carry out an upgrade of the send-out capacity |
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
© POTEN & PARTNERS 2009 CONFIDENTIAL |
Exhibit (c)(10)
EXPERT ADVISORS TO THE LNG AND NATURAL GAS INDUSTRIES www.poten.com |
© POTEN & PARTNERS 2009 CONFIDENTIAL 9 9 9 |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Höegh Gallant and Höegh Grace have slightly reduced loading and discharging rates compared with similar sized vessels. • Poor speed (11 knots), loading and discharge times (5,000m3 loading rate, 38 hours bulk discharge time) • Send-out capacity could be increased, addition of heater to change open loop to hybrid or closed loop heating for regasification, etc. could all be installed but time required will be significant (~2 years) for ordering and installation of long lead regas equipment • Budgeted $35 million for upgrade of send out rate and “at least 2 months” for this work appears insufficient, particularly if higher capacity pumps and larger piping is required for regasification using seawater heating. • Potentially greater benefit in FSRU employment with existing equipment (after docking) for higher potential charter return if existing charter is terminated. • Main modification required could be installation of a high-pressure manifold along the ship’s side, forward of the main manifold. Current HP manifold is arranged for gas send-out over the bow. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Höegh Grace could be released from charter end 2026 – market still expected to be strong at this time as no newbuild FSRUs are predicted by that time and maybe limited number of conversions • Höegh Gallant on charter to end 2031 • On charter to Total until end 2029 (Neptune) and mid 2030 (Cape Ann) • Significantly reduced permitting, reduced operational risk if not in congested ports, suitable for water depths >35m and can operate in reasonably exposed locations • First opportunity could be 2027 with Höegh Grace if charter is terminated, unless PGN FSRU Lampung charter is cancelled as a result of arbitration. • Conversion of a suitable second-hand vessel would take ~2 years (with some opportunity to trade as LNGC during preliminary engineering and equipment ordering period) but LNGC charter rates set to remain relatively high |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Cost allocation method may not reflect the actual outlay that could be expected, unless reflected elsewhere in CAPEX allocations • Financial Model suggests dry dock/survey costs of $4m every 5 years ($0.8m/yr) – trading vessels (LNGCs) over 15 years of age will dry dock every 2.5 years and increased frequency/cost of inspection for FSRUs. Noted that for Cape Ann and Neptune, dry docking costs are a pass-through to charterer and therefore not a HMLP capital cost • Docking cost allocation usually includes mid life refurbishment work to replace obsolete equipment or equipment no longer supported by the manufacturer, general upgrades and to address changes in legislation, etc. Cape Ann and Neptune will require extensive docking at end of charter at 20 years (4th special survey) if charterer’s option periods not taken up • Dry docking interval is stated as being 5 years, however, an increased frequency of docking/inspection is required for vessels over 15 years of age and appear not properly reflected in the Financial Model • No allowance has been included for the possible dry docking of Hoegh Grace in early 2027 if SPEC do not extend the charter period beyond the initial 10 year term. Class/Flag unlikely to accept a further extended term as FSRU in another location without dry docking and “resetting” extended survey cycle. |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Provide a high-level description of the FSRU market through 2035. This assessment will consider, to the extent feasible, the impact on the FSRU market of the Russian/Ukraine conflict and the requirement to reduce European dependency on Russian pipeline gas. The description will include our base, high and low forecast of the number of FSRUs that are likely to be employed worldwide and the type of projects in which they are likely to be employed. • Identify the segments of the FSRU market in which Höegh MLP is likely to compete and make a high-level assessment of the competitors that Höegh MLP is likely to face in seeking to secure new projects. We will provide base, high and low forecasts through 2035 of the number of additional FSRU projects that Höegh MLP could secure. • Provide base, high and low forecasts of annual FSRU charter rates for new vessels through 2035 based on our LNG supply and demand forecasts, scenarios for FSRU, FSU and LNG carrier requirements and drivers. • Provide base, high and low annual forecasts of long-term rechartering rates to 2035 for Höegh MLP’s current fleet for service as FSRUs and will provide a perspective on range of length of time expected to recharter an FSRU. We will analyze and explain the difference for divergence between these rechartering rate forecasts and the forecasted charter rates for new FSRUs per item 3 above. • Poten will comment on the technical feasibility of using the FSRUs in Höegh MLP’s current fleet as LNG carriers. Poten will provide base, high and low forecasted annual charter rates to 2035, taking into account the technical specifications of Höegh MLP’s assets, if they are so used as LNG carriers. • Poten will review and comment on the relevant assumptions in financial forecasts provided by management of Höegh MLP. • Poten will share views on how LNG carrier conversions to FSRUs will impact the supply / demand balance and resultant charter rates through 2035. • To the extent it is not covered in the preceding categories, Poten will provide estimated recharter rate, contract period and idle time for the FSRU Lampung in the event PGN were to terminate the contract today. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Lampung FSRU • Cape Ann • Neptune • Höegh Grace • Höegh Gallant • Neptune is suitably equipped and able to be used as an FSRU • Each vessel is also addressed in separate sections of the report |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • These include FSRU rates and employment prospects after the termination of current contracts. • Neither of these documents appears to include any impact of EEXI/CII requirements post 1/1/2023 |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • However, X-DF and ME-GI are not propulsion systems used for FSRUs • DFDE/TFDE remain the propulsion system of choice for FSRUs due to their flexibility in meeting varying power demands associated with FSRU operations including varying send-out rates. • A significant proportion of the existing LNGC fleet has similar boil off rates of 0.12% – 0.15% • The FSRU and LNGC markets are segmented with different rates applying based on size, propulsion and spec. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • All but three of the newbuilds are aged 15 years or less. Most vessels aged 15+ are conversions. • Around half of the newbuilds are 5 years old or less. • However, one vessel - LNG Vesta - is currently mooted for FSRU conversion by KARMOL. • Built 1994, 127,547m3 capacity.is a similar vessel to other KARMOL conversions. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Cape Ann/Neptune lightweight at 31,676mt • Höegh Grace/Gallant lightweight at about 34,755mt • Lampung lightweight at about 33,957mt • Recent LNGC scrapping sales have been in the order of $20.0m • Uplift for exotic metals could increase current scrap values, but not included • Regasification equipment could have intrinsic value for future LNGC conversions and could reduce lead time for certain cryogenic equipment |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Efficiency of LNGCs is based on data that combines all LNGC propulsion systems into one “bucket” – ST to X-DF • Steam turbine vessels make up 36% of the existing LNGC fleet • D/TFDE vessels account for 30% of the LNGC fleet • HMLP does not operate any steam turbine vessels • Speeds will be reduced (12 knots loaded, slower ballast speed?) or speed matched to boil off • Some vessels may become uneconomic to operate • Charterers likely to avoid STs based on lower CII ratings • Winter spot charter rates and term charter rates may be significantly higher, summer charter rates higher if STs are idled and available capacity cut • New builds unable to meet demand in short term |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL LampungL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Memoranda are notes pertaining to the vessel and can be removed when any conditions are complied with, or the memorandum is not longer valid. • Conditions of Class normally relate to damage or other matters that needs to be repaired or addressed within a stated period of time |
© POTEN & PARTNERS 2009 CONFIDENTIAL ARTNERS 2 2 2 2 2009 TI I I IAL AL AL AL AL |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • These limitations mean that the inner hull is under strength for typical dynamic operations. Although compliant with class requirements, it gives a lighter steel weight. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Engine is for propulsion to site only • A conventional FSRU capable of trading as an LNGC will have a manifold configuration of L-L-V-L-L to enable multiple loading arms to be connected. • A conventional FSRU capable of trading as an LNGC will normally have a loading rate in excess of 10,000m3/hr, and accept LNG in a STS operation at a transfer rate of 6,000 -8,000m3/hr dependent on vapor management • Normal laytime allowed for LNG loading or discharge is 36 hours. • A conventional FSRU capable of trading as an LNGC will typically have 2 cargo pumps per tank with capacities each in excess of 1,500m3/hr |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Limits options for future use and locations • Send out typically >500mmscf/d required in most locations, but may not always be fully utilized |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Höegh have provided an updated estimate for carrying out upgrade work which includes increasing send-out capacity with the addition of 3 regasification trains of 125 mmscf/d. This estimate is around $80 million (up from $35 million) and includes additional power generation, increased open loop water seawater system capacity, etc. • The time required in a repair yard for the regasification system upgrade would be 3-4 months. • Additional manifold arrangements and increase in load/discharge rates would also be required to trade. • Höegh have provided an estimate of the cost of re-engining Lampung for trading purposes which would also include upgrade of manifolds and cargo pumps for higher loading/discharging rates, new power system for 18 knots service speed, new propellor, etc. • Including regasification system upgrades, repowering the vessel would incur a cost in the range $140- 170 million and require 5-6 months in a repair yard for the upgrade work. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Seawater temperatures over about 15°C (60°F) are generally suitable for open loop regasification • Some local coastal cold water currents may slightly modify this broad categorization • Some regulatory jurisdictions (including some parts of Australia) would have concerns over the “plume” of discharged cold water. • Its low regasified LNG send-out rate is not ideal but would offer a near immediate stop-gap solution until a larger send-out capacity FSRU is available • Main modification required during any drydocking would be installation of an HP manifold forward of the main manifold • Modifications would most likely not be required – similar level of usage as today • Mooring configuration has to be considered – water depth about 45m |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Some local cold coastal currents may slightly modify this broad categorization |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • Memoranda are notes pertaining to the vessel and can be removed when any conditions are complied with, or the memorandum is not longer valid. • Conditions of Class normally relate to damage or other matters that needs to be repaired or addressed within a stated period of time |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • This is lower than is typically the case for LNGCs (10, 12 or even 14,000m3/hr) • Typically, bulk discharge time is closer to 12 hours • An LNGC built at a similar time to Hoegh Grace will typically have main cargo pumps with a rated capacity in excess of 1,500m3/hr (more typically around 1,750m3/hr each) • In future, as carbon dioxide emissions reporting becomes significant, the service speed is unlikely to be an important consideration. A A A A ART RT RT RT RTNE NE NE NE NERS RS RS R RS 2 2 2 2 200 0 0 09 TI I I IAL AL AL AL AL |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • However, the vessel is known to have experienced a technical problem with a cargo pump at the Futtsu LNG terminal in Japan in 1Q 2020 which resulted in a penalty of $11.016.75 from a 3.97 hour delay in discharge time. |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • This is lower than is typically the case for LNGCs (10, 12 or even 14,000m3/hr) • Typically, bulk discharge time is closer to 12 hours • An LNGC built at a similar time to Hoegh Grace will typically have main cargo pumps with a rated capacity in excess of 1,500m3/hr (more typically around 1,750m3/hr each) • In future, as carbon dioxide emissions reporting becomes significant, the service speed is unlikely to be an important consideration. |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • Operated in this mode, the vessels require dry docking on a regular basis • The STL connection arrangement offers a significantly cheaper mooring solution in exposed locations or water depths of greater than about 35m • The vessels have dynamic positioning capability for use with picking up an STL connection in open water. ARTNERS 2 2 2 2 2009 TI TI I I IAL AL AL AL AL |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • Not clear if charterers bear costs of equipment replacement due to obsolescence or that is an owner’s cost. • May be of increasing “value” in the market as older and smaller steam turbine vessels are phased out due to EEXI/CII restrictions. |
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© POTEN & PARTNERS 2009 CONFIDENTIAL 1 Ballast engine room tank port 2 Ballast engine room tank starboard 3 Aft peak tank 4 Double bottom/side tank 1P, 1S, 2P, 2S, 3P |
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© POTEN & PARTNERS 2009 CONFIDENTIAL ° • Vessel is only able to operate in closed loop heating system – suitable for cold water locations but consumes more fuel for cargo heating • When operating in N+1 configuration, send-out rate is 500mmscf/d ART RTNE E ERS 2 2 2 2 200 0 00 09 9 9 TI IAL AL AL AL AL |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • The vessel has loaded at Idku in Egypt and discharged at Revithoussa in Greece. Currently at anchor outside port limits Malta after loading at Idku |
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© POTEN & PARTNERS 2009 CONFIDENTIAL x Midships draft not to exceed 12.4m x Minimum forward draft of 8.64m without limitation on ballast tank filling x If forward draft is <8.64m, vessel to take precautions to avoid slamming x Cargo tank filling limits not to be between 2.75m to 70% tank height in open water (Poten note - to minimize risk of sloshing damage to tanks) x Maximum allowable relief valve setting is 0.25 Bar x If cargo tanks 2-4 are empty, ballast level in ballast tanks must be to at least the level of the inner bottom x |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • 3 months engineering and design work necessary to identify requirements • Cryogenic equipment lead times could be 15-18 months - Based on number of LNGCs under construction, overhang of shipyard orders and reduction in nickel availability from Russia • Conversion time of 3 months – extent of conversion and work required will depend on specification, LNG heating requirements and any other work such as replacement of obsolete/soon to be obsolete equipment (e.g. IAS, F&GD) • Mobilization to site • Upgrades will add more to the conversion cost • Steam turbine conversion costs will be about $80 million based on requirement for additional generating capacity and power management system installation • Loading LNG on mobilization voyage for commissioning terminal can advance charter income • Also eliminates gas up/cool down time/cost and STS transfer on arrival at site before commissioning |
© POTEN & PARTNERS 2009 CONFIDENTIAL • The older the vessel, the higher the conversion costs, but cheaper the purchase price • With an older ST vessel, there is limited LNG capacity against current parcel sizes and major “surgery” required to convert and upgrade • Significant upgrades required in auxiliary systems – sewage systems, air conditioning, incineration, utilities, etc. as well as installation of regasification system. • Single FSRU operators tied to local projects are unlikely to be competitors in the international market • Cost of conversion or uplift on cost of newbuild over LNGC price still remains a barrier unless an owner is converting/building for a specific project for which already pre-selected. |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • Whether this time scale is still applicable to these projects if LNG prices increase significantly on supply shortages remains to be seen • LNG pricing and future FSRU charter rates will make a number of these projects marginal at best • Further accentuated by the cut in pipeline gas supplies to Bulgaria and Poland |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Only suitable for warm seawater conditions and has low send-out rate • Would require significant increase in regas capacity, LNG receiving rate, additional HP manifold for alongside mooring and full dry docking • Yard time minimum 3-4 months and about $80 million to upgrade send-out capacity • Positioning voyage to Europe (basis Malta, mid Mediterranean) would take 27 days at 10 knots (via Suez). ö ö |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Germany 4, Italy 2, France 1, Poland 1, Finland 1 and Latvia 1 • Finland is discussing “”sharing” an FSRU with Estonia through the Baltic Connector pipeline • Turkey and Greece may also need additional FSRUs • UK may need to reinstate the Teesport FSRU facility • 4 FSRUs known to have been taken, plus a regas barge – Golar Tundra purchased for use in Italy – Other FSRU charters being worked - Some charters apparently have potential break options at 5 years (with a penalty) • Newbuilds would take too long to come to market, unless Owner can convince shipyard to change existing LNGC order to an FSRU • Replacement vessels/cheaper charter rates may not be an option |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Permitting • Environmental restrictions • Equipment availability • EPC/Construction supervision (multiple construction projects in parallel) • Funding – shareholder criticism of financial institutions’ lending for oil and gas projects • Existing FSRU charterers may want to negotiate extension of existing FSRU charters if no alternative vessels exist in the market |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • Work to be undertakan will also increase with vessel age • If the dry dockings of these vessels is protracted, or there is any significant increase in dry dock scope or costs, Hoegh will be exposed to increased loss of hire and these increased costs. |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • DD costs appear to be $4m over a 5 year period for each vessel. • While the DD cost allocation in the model is simple and neat it does not reflect the actual outlay that could be expected. • If these costs are not reflected in CAPEX allocations elsewhere then the model will be light on allocation for ongoing costs. • Cape Ann and Neptune will be 15 years in 2024 – 2025. The other vessels will be 15 years old on or around 2030. For LNGCs after 15years of age vessel docking cycle is every 2.5 years as opposed to 5 years, for FSRUs this results in an increased inspection frequency/cost. • Includes allocation for regular mid-life refits in the order of $10m every 15years, $2.0m every 2.5years. • Mid life refit/refurbishment will include replacement of obsolete equipment/equipment no longer supported by manufacturers and general upgrades required to improve efficiency of operations, changes in legislation, etc.. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • For each FSRU there appears to be an initial value which is depreciated by age? • Are they “charter adjusted” or “charter free”? • If charter free, all the values appear low at the moment |
© POTEN & PARTNERS 2009 CONFIDENTIAL • $4m is indicated in 1Q 2026, first charter period ends 31/12/2026 • $4m allowance may be sufficient for continued in water surveys but not appropriate for dry dock after 10 years on station as an FSRU • Unlikely that Class/Flag will accept a follow-on FSRU charter after 10 years without docking • Docking costs for Neptune and Cape Ann are pass through costs to the charterer. There will invariably be some element of Owners costs in drydockings but amount should be insignificant • Neptune’s 20-year docking cost appears unrealistic – mid life refurbishment (MLR) and replacement of obsolete/unsupported equipment expected at this time likely to increase the cost of dry dock. 20-year docking costs likely to be minimum $10m • Cape Ann likely to require MLR in 2030 at end of Total charter, with similar costs as Neptune |
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Exhibit (c)(11)
CONFIDENTIAL TREATMENT REQUESTED
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© POTEN & PARTNERS 2009 CONFIDENTIAL • This assessment is to provide a base, high and low forecast of the number of FSRUs required • Explanation of the divergence between rechartering rates and forecasted charter rates for new FSRUs A A ART RT RT T TNE NE NE NE NERS RS RS RS RS 2 2 200 00 00 00 009 9 9 9 9 |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • Growth of FSRUs to service markets is driven by capital cost savings and shorter implementation schedules. • FSRU fleet has grown quickly in response to demand. There are currently 46 existing FSRUs, none on order. • New players have entered the market; increasing competition, and reducing opportunities for established players. • Cost and time savings, flexibility, lower credit needs and security of supply (Europe) will continue to drive demand. • There are 60+ planned FSRU projects. N.B. many are in markets sensitive to LNG price and FSRU charter rates. • Some vessels are “allocated” to future start-ups, and current charters could be re-negotiated / extended. • The FSRU fleet currently comprises nine conversions. • Depending on the storage capacity requirement, there is a fleet of available conventional LNG carriers that can be converted to FSRUs. However, the vessels are mostly older and smaller compared to the current standard LNGC. • About $50 million – $80 million conversion cost, plus out of service lost revenue. • Timing of conversion vs newbuild – 18 months vs 3-4 years. The earliest delivery for a newbuild is likely to be 2025 - 2026, whilst a conversion could be operational by the end of 2023. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • The LNG market faced adversity in 2020, but demand declines reversed by the end of the year. • The environment took a front row in 2021, while Qatar aggressively secured buyers and increased market share. • Europe will require increasing gas imports as indigenous production continues to decline. • US and Qatar could benefit; however, they are unable to supply all of Europe’s requirements. • Global demand projected to reach 570 MMt/y by 2040, with Asia Pacific dominating global demand. • North America, East Africa, Qatar and Russia competing for markets post 2025. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Diversification from Russian supply and displacement of other fuels drives European FSRU demand, restricts FSRU availability elsewhere. • At the present time: requirement for 4 FSRUs in Germany, 2 in Italy, 1 in France, 1 in each of Poland, Latvia and a shared FSRU for Finland and Estonia. • It is likely that other European countries will be looking for FSRUs as the conflict continues.. • Asia has large growth potential but is a more price- sensitive market. Growth in the Middle East is driven by increased air conditioning load during northern hemisphere summers. Demand in South America is driven by hydro constraints. A number of projects are likely to be delayed, e.g., due to price sensitivity. • N.B. it is difficult to assess number of conversions that will take place. There will be plenty of need for ST vessels as FSUs and regional trades. In addition, available LNGCs may not be suitable for a lot of projects.ST conversions are more expensive than D/TFDE, and barriers to entry are also high. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • However, Cape Ann and Neptune are ideally suited to the colder waters of the Baltic and NWE where seawater temperatures do not support open loop operations. • Their success will be dependent on LNGC conversion time and demonstrating sufficient experience in operations. • They could potentially secure a premium charter rate based on timing and availability but equally a discount if they are not considered experienced. • The main competitors will be those with significant LNGC fleets that they control (rather than locked into a project). • MOL, SeaPeak (Teekay?), Gaslog, etc, for example and those with sufficient cash resources or access to cheap money. Sinokor is possibly not a competitor as no real LNGC operating experience. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Until the sudden recent rise in demand, the FRSU market had suffered from overcapacity. • Increases in LNGC charter rates over last winter (2021/22) and had already increased FSRU owner charter rate expectations and scarcity will also push charter rates up. • Impact of this is that planned projects won’t/can’t go ahead within their proposed schedules. • In practice, we believe CAPEX charter rates may have been closer to $120,000/d - $130,000/d. Spare vessels are limited - only a few ships are available and only three could be released from contracts this year. • The earliest delivery for a newbuild is likely to be 2026 or conversion by end 2023. • EEXI impact will also prompt newbuildings with some owners switching to alternative fuelled tonnage – slot capacity will remain high most likely to 2030 and beyond. • Delays to the 60+ planned projects will result in pent-up demand in the future, particularly if LNG prices moderate • Those with FSRUs on charter and charter terminating in 3-5 years would be expected to extend the charter, renegotiating for the FSRU currently available versus trying to replace it with a larger more efficient FSRU – as none would likely exist in the market. The question is when would or should they renegotiate? |
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
© POTEN & PARTNERS 2009 CONFIDENTIAL • LNGCs are at about $235 million and FSRUs at about $275 million. • Likely to be continued upward pressure on prices, particularly for steel, cutbacks in nickel and aluminium supplies from Russia. Further upward pressure from shipyard capacity constraints, containership orders, possible regeneration of VLCC and bulk carrier fleets. • The market is still extremely volatile at this moment to offer a hard opinion on future charter CAPEX rates – European FSRU demand is still evolving . • $80,000/d - $90,000/d CAPEX is a good basis for starting negotiations. • Our view is that the $ assumed CAPEX rate for the next charter is too low for today, even for Lampung – it may be the only FSRU available • Our view is that HMLP’s assumed future CAPEX of $ for Cape Ann and Neptune when they come off charter in 2029/2030 could be much higher – $ - $ – At the lower end, it could be $ - $ as over 50% depreciated by that time. • N.B. FSRU rate for a conversion would be around $90,000/day – Shipowners unlikely to convert to FSRU on speculative basis, only against a specific project requirement. |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • These provide significant financing benefits to sponsors by lowering upfront investments • FSRUs’ much lower CAPEX could outweigh the cost of chartering the FSRU, and in general the overall terminal costs for FSRU-based import projects end up lower than onshore LNG import projects • But this depends on overall size of LNG demand and impact of economies of scale – typically favouring onshore terminals for higher volumes of throughput and storage • Power generation cost savings by displacing oil- based fuels (e.g., diesel oil) with cheaper regasified LNG PART T T T TNE E E NERS 2009 N N N NTI TI TI TI TIAL AL A A A |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Contract signing to steel cutting will be about 12 months, which involves the procurement of equipment and plan approval work. • The construction period is around 18 months which includes about 4-5 months from keel laying to launching and the remaining time fitting out the cargo tanks, installing the cargo system, sea and gas trials before delivery. • LNG carrier (LNGC) construction follows a similar schedule and stages but can usually be completed in 27-30 months |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • All but three of the newbuilds are aged 15 years or less. Most vessels aged 15+ are conversions. • Around half of the newbuilds are 5 years old or less. • However, one vessel - LNG Vesta - is currently mooted for FSRU conversion by KARMOL. • Built 1994, 127,547m3 capacity. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Only one FSU, the 173,400m3 Bahrain Spirit, is a newbuild. The other five FSUs are conversions of older vessels; 125,000m3 – 130,000m3 in capacity. • The FRU is a 28,000m3 unit, Torman, owned by GasFin for the Tema LNG project in Ghana. • Owned by GTLK (Russian State Transport Leasing Company) and MOL; for Novatek’s transshipment operations for its Arctic 2 LNG project in Russia. • The vessels will be stationed at each of Bechevinskaya Bay in the Kamchatka Territory and Ura Bay at Murmansk. They will be used to reload LNG from ice-class ARC7 LNGCs to conventional LNGCs. • Koryak FSU is due to be delivered by the end of Q3 this year, while Saam FSU is due by the end of Q4. The first train for Arctic 2 LNG is due to start in 2023. • The FSUs have entered into bareboat charter agreements with Arctic Transshipment, a joint venture of Novatek and TotalEnergies. |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • The situation in Ukraine has resulted in plans to rapidly reduce reliance on Russian gas. FSRUs are seen as the fastest way to boost LNG imports. France, Germany, Italy, the Netherlands etc have announced plans for FSRUs. • FSRUs are most often leased rather than purchased by the terminal developer. Initial capital outlays can therefore be 3-4 times less than for conventional onshore regasification projects, as the cost of the FSRU becomes an ongoing lease rather than an upfront capital expenditure to the developer. • FSRUs could offer a significantly shorter development timeframe Around 3 years even for a newbuild (subject to yard slot availability) vs. at least 4 years construction schedule for a conventional onshore terminal. • Regasification vessels can be used on a seasonal basis and in niche markets • FSRUs can also be used as a bridging solution, delaying need for onshore investment A A A ART RT RT RT RTNE NE NE NE NERS RS RS RS RS 2 2 2 2 200 00 00 00 009 9 9 9 9 TI I I I IAL AL AL AL AL |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • Gas demand doesn’t go away and probably only increases. • These locations have not built onshore replacement regasification/storage facilities. • Charterers will not get more modern efficient FSRUs from the market, so renewal of existing charter may be their only option for continuity of supply. • The FSRU fleet currently comprises nine conversions. • Depending on the storage capacity requirement, there is a fleet of available conventional LNG carriers that can be converted to FSRUs. • However, the vessels are mostly older and smaller (125,000m3 – 138,000m3) compared to the current standard LNGC of 160,000m3 – 180,000m3. • About $50 million – $80 million conversion cost, plus out of service lost revenue. • Timing of conversion vs newbuild – 18 months vs 3-4 years. The earliest delivery for a newbuild is likely to be 2025 - 2026, whilst a conversion could be operational by the end of 2023. • Other option could be for an owner to convert an existing LNGC order or option to an FSRU provided builder is willing. |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • 2020 demand of 357 MMt was slightly lower than in 2019, the first decline in demand since 2013. • The Covid-19 pandemic negatively impacted LNG growth in 2020 – we were anticipating around 372 MMt pre-Covid. • The warm winter of 2019-20 in North Asia was the second in a row. By summer Europe could not absorb the surplus. • The oil price war and oversupply of LNG drove spot LNG prices to record lows, below US variable costs. • US supply was curtailed by as much as 75% as offtakers canceled cargoes. • Demand recovered in the second half of the year, causing prices to recover. • In Australia, Gorgon and Prelude faced extended partial or full shutdowns to correct operating problems. • Hurricanes Laura and Delta in the US Gulf interrupted deliveries from Cameron and Sabine. • Fire at Snohvit in Norway – supply is not expected to restart until May 2022. |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • Very uncertain situation – the weather in the Northern Hemisphere this coming winter will be a key determinant |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Carbon neutral LNG cargoes became the flavor of the day, but is this sustainable economically? • IMO shipping regulations - will place further pressure on Steam Turbine vessels, potentially impacting global fleet. • Qatar has emerged as a key incremental supplier of LNG this decade – as other LNG supply regions struggle. • US and Canadian projects have found it more difficult to secure buyers, raise financing, and pass environmental hurdles - particularly in the case of Canadian projects. However, pre-FID US projects are gaining new impetus (and long-term sales) as a result of the unexpectedly strong demand rebound and resulting price environment. • Delays in Mozambique due to precarious security situation – Qatar start-ups may temper the market impact of Mozambique delays - if short lived. Papua New Guinea projects delay as government wanted larger share of revenues. • Asian LNG markets have recovered post-Covid and sustained aggressive global growth. • Both Atlantic and Pacific (TTF, JKM) spot prices closed out the year at >$30/MMBtu and US Gulf LNG production was producing at maximum as a result, with extremely high margins on offer. – Prices were surprisingly strong even during shoulder and summer months (driven by high oil prices, cold winter in Asia, and strong economic recovery post pandemic). |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Russian access to deep water seaports in the Black Sea • NATO expansion – is Ukraine next? Counter Western hegemony in the region • Nord Stream 2 and its geopolitical significance • Gas cut off to Poland and Bulgaria • Yes – but to a degree, as there are commercial, logistical and market challenges • Can’t substitute Russian gas to Europe – and so far Russia has fulfilled its contracted obligations; though supply could be shut off at any time. • Price impacts on LNG spot A A A ART RT T RTNE NE E NERS RS RS 2009 TIAL A |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Volumes to Germany and other northern European markets were delivered via Yamal. • Prior to the start up of Nord Stream, most Russian gas transited Ukraine. • With the start up of Nord Stream, Russian gas has flowed directly to Germany, and caused the reversal of flows in the Slovakia-Czech Republic axis. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • LNG is the marginal price-setting supply source. • European gas prices are in equilibrium with Asian spot LNG prices. • Economic rebound, particularly in China and other parts of Asia, led to increased LNG demand. • In the unusually cold winter of 2020-21 in northern Asia, buyers (particularly in China) were caught short, and they aggressively sought to secure spot cargoes. |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • The main indigenous sources (UK, Netherlands and Germany) are in the decline phase, although UK production has increased modestly since 2013. • Production from the Netherlands’ Groningen field has declined particularly quickly. • Snohvit is just starting up after lengthy shutdown. |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Global demand projected to reach 570 MMt/y by 2040, with Asia Pacific dominating global demand. • Increase in trade to 2025 is driven by LNG supply already under construction, much of which is contracted long-term. However, a material amount (particularly from US projects) is still seeking final end-user buyers. • Qatar will increase market share with the addition of its four new mega-trains, bringing its supply capacity to 110 MMt/y. • Supply from East Africa and North America is projected to reach 188 MMt/y by 2040, around one third of global production. • Russian plans could be jeopardized by Ukraine war and new supply trains, including Arctic 2, may come under pressure from sanctions. • Some countries may import LNG, circumventing sanctions observed by other countries. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • In the period from 2020 to 2025, there is expected to be sufficient LNG production from existing and under construction projects to sustain demand growth. • There is opportunity now for new projects to take FID to meet post-2026 demand. Qatar has pre-emptively captured uncovered LNG demand. • The Low LNG Demand case scenarios assumes Forecast GDP growth rates 90-95% of base case in the key markets, increased penetration of RES in electricity generation and greater competition from other sources of energy compared to LNG. • The High LNG Demand case scenario assumes forecast GDP growth rates 105-110% of base case, slower penetration of RES in electricity generation and an upside view for growth in niche markets. • 2040 demand ranges between 515 MMt and 629 MMt |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • Strong economic growth and increased electrification drives demand. FSRUs are well positioned to meet import growth requirements. • Renewable penetration and increased domestic production will eventually limit LNG imports. • FSRU utilisation increases during drought years. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • LNG carriers and FSRUs are built with a 40-year design life based on North Atlantic weather conditions. • Older FSRUs tended to come with smaller storage capacity. Also, it was mainly the older Moss-type ships, with storage capacities less than 138,000 m3 that were converted into FSRUs. • The average size of new LNG carriers is 175,000m3. This means that the LNG carrier would have to stay docked for longer periods of time to offload or deliver a partial load. Also, it reduces options to redeploy as an LNG carrier. • Smaller storage availability also reduces buffer and increases risks of running short of LNG in case an LNG carrier is delayed in-route. Many projects/countries have opted for larger FSRUs in order to increase security of supply, a recent example being Pakistan. • In addition, boil-off-rate and power generation efficiency are worse for these older ships. A A A ART RT RT RT RTNERS 2009 TI I I I IAL AL AL AL AL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Base Scenario: assuming our Base Case demand for FSRUs, matched against our current FSRU supply picture (both existing and in the orderbook). • Low Scenario: assuming a conservative demand for FSRUs, matched against our current FSRU supply picture – but assuming no FSRU retirements. This case reflects a world where the older, smaller FSRUs can still compete for smaller, price sensitive markets – despite the logistical difficulties of limited storage capacity. • High Scenario: assuming a higher demand for FSRUs, matched against our current FSRU supply picture (both existing and in the orderbook) – assuming gradual retirements of the older, smaller FSRUs. This is a more bullish view for FSRU providers, particularly for the ones with a more modern fleet. • When the demand crosses availability of existing FSRUs, the implication is that a new FSRU would have to be ordered from a shipyard to meet the requirement or be converted from an existing LNGC. • It is too difficult at the moment to make any realistic forecasts beyond 2030 as current climate is too uncertain – too many variables which are outside normal forecasting parameters. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • N.B. our supply curve does not include forecasts for new orders / conversions. • Near-term demand would be met by new conversions • A number of projects are likely to be delayed; especially due to LNG/charter rate price sensitivity. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • N.B. our supply curve does not include forecasts for new orders / conversions. • More projects are likely to be delayed; especially due to LNG/charter rate price sensitivity. • Near-term demand would be met by new conversions; and / or a number of projects are likely to be delayed. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • N.B. our supply curve does not include forecasts for new orders / conversions. • Deepening commoditisation of FSRU infrastructure and streamlining of project completion is crucial. • If smaller vessels are not phased out, this requirement would be 30 vessels. |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • • • • • • • • • • • • • • • • • • |
© POTEN & PARTNERS 2009 CONFIDENTIAL • These players, all shipping companies, have been in the FSRU market for 10 – 20 years. • Players developing local FSRU projects and taking ownership of the vessels. • Players who own conventional LNGCs and are new market entrants into the FSRU market. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Excelerate: 10 vessels • Exmar: 1 vessel • Golar / NFE: 6 vessels (including 3 conversions) • Golar: 1 vessel • Höegh LNG (including HMLP): 8 vessels • Höegh LNG, MOL, TG: 2 vessels • MOL: 1 vessel • BW Gas: 5 vessels (including 2 conversions) • From 100% in 2005 - 2012 to 74% today. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Höegh has the most modern fleet (average age of 7 years) - all are newbuilds, and most are 170,000m3. • Höegh and Excelerate have larger, more modern fleets but do not have experience in conversions. • Golar / NFE has the least modern fleet, due to its three smaller, converted FSRUs. |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • A converted FSRU, stationed in Italy. • Gazprom – Newbuild in Russia, delivered 2018 • Jaya Samudra Karunia – Small-scale newbuild, to be stationed in Indonesia, delivered in 2018 • Kolin / Kalyon – Newbuild in Turkey, delivered 2019 • BOTAS – Newbuild in Turkey, delivered 2020 • LNG Hrvatska – Conversion in Croatia, built 2020 • Swan Energy – Newbuild in India, delivered 2020 • Jawa Satu Power – Newbuild in Indonesia, 2021 • Two converted FSRUs, built in 2021; for LNG to power projects in Senegal and Mozambique. • Only employs FSRUs with its power barges. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Reduced barriers to entry in terms of price and wider LNG experience across the industry; often driven by local companies / entrepreneurs. • However, by doing it themselves, they have to employ greater amount of up-front capital in securing the FSRU – it would normally be OPEX for the charter payments. • Most of the activity has been in Europe – Italy, Russia, Turkey and Croatia. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Maran Gas is a Greek LNG ship owner / operator established in 2003. Its first LNG vessels were delivered in 2005. • Maran Gas owns a total of 53 LNG vessels, including 10 vessels currently under construction. – This total includes 19 operational conventional LNGCs co-owned with Nakilat. • Excelerate signed a five-year bareboat charter with Maran Gas for a 173,400m3 newbuild FSRU, Excelerate Sequoia, delivered in 2020. The agreement gives Excelerate the option to buy the vessel during the charter. – Excelerate Technical Management provides ship management for the vessel. • Excelerate Sequoia can operate as a trading LNGC or an FSRU. It is currently operating as an FSRU in Bahia, Brazil. • Dynagas is a Greek LNG ship owner / operator established in 2004. Its first LNG vessels were delivered in 2007. • Dynagas owns a total of 23 LNG vessels, including five vessels currently under construction. – This total includes five operational Arc-7 ice class vessels, and two operational FSRUs. – The other 16 vessels are conventional LNG carriers. • Dynagas took delivery of two 174,000m3 FSRU newbuilds: Transgas Power and Transgas Force. • Both vessels have been operating as conventional LNG carriers since delivery last year. However, both vessels have recently (March 2022) entered charter deals for German FSRU projects. • These speculative orders were driven by Dynagas’ bullish view of the FSRU market. The vessels were specifically designed to also be able to operate as LNGCs. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Such players may be able to offer cargoes to support their move into infrastructure. • However, not “too speculative” - a more conservative approach compared to conventional LNG carriers. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Owners do not typically contract for multiple FSRUs on a speculative basis. • Based on a 3-year contract to delivery schedule, established owners are likely to have one FSRU on speculative build at any time against the prospect of being able to place it in a project. • Cost of FSRU is $40million - $50 million more than an equivalent sized LNGC so more “calculated” speculation that vessel will get placed if built. • Owner does not really want to have to trade in LNGC market and get lower return in early life of vessel. • Once past the feasibility stage, many FSRU projects come close, but can fail to develop for various reasons. • Estimated that the success rate (i.e., getting to a signed charter party agreement) is worse than 1 in 4 projects due to competition and “project failure”. |
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© POTEN & PARTNERS 2009 CONFIDENTIAL • Through an FSRU Time-Charter Agreement (TCA) – Project sponsor charters/leases the vessel from the FSRU Owner for a fixed time period. – FSRU Owner just charters out the FSRU and typically has no terminal ownership or fixed infrastructure development responsibilities – Charter rate, length of time charter, option periods can vary between projects • Through a Terminal Use Agreement (TUA) – FSRU Owner is also the owner of the import terminal and receives a service fee for use of the terminal – FSRU Owner is also the regasification service provider – Typically includes the development of fixed infrastructure such as docking system, offshore pipelines (as part of a full regasification project) • Turn-key solutions such as Build-Operate-Own-Transfer (BOOT) – FSRU provider builds and operates the import facility (including providing the FSRU and required fixed infrastructure such as docking system, jetty and pipeline to shore) as well as LNG supply for a fixed period until the asset is transferred to the project offtaker – Typically, this comes through a Gas Sales Agreement (GSA) at the point of consumption – Services include LNG supply, FSRU provision, regas services and fixed infrastructure to deliver regasified LNG to customers • In this report, we will primarily be focusing on charter rates expected in Time-Charter Agreements, where the FSRU Owner only leases the FSRU to a Project . |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Contract prices have steadily reduced and now sit at a premium of about $40 million above the capital cost of an equivalent sized LNG carrier. • Additional technical requirements or non-standard mooring arrangements can add a further $10-$20 million to the overall contract price. A A A A ART RT RT RT RTNE NE NE NE NERS RS RS RS RS 2 2 200 00 00 0 09 9 9 9 9 TIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • They are ultimately sponsored by state-owned players motivated primarily by wider strategic considerations, particularly energy security concerns, rather than profits. • Expected demand also frequently fails to materialise. • Frequently imports are made into countries where gas and/or power costs are subsidised. • N.B. there are a few cases where demand has exceeded FSRU capacity and larger or multiple vessels required. • Plus, the relative lack of competition had allowed them to enjoy high rates of return. • Rates continue to be strong for individual projects, but pressure on margins is likely to increase, eroding some profitability, either through lower charter rates or having to carry unchartered vessels awaiting employment. • They have typically structured their involvement so that the risks and losses are borne by other players. • Rather, they vary depending on the competitive conditions surrounding each bid. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Older, smaller and less efficient FSRUs, mostly conversions, are likely to be let out at $80- 85,000/day. • Existing, modern FSRUs can be hired at $95- 100,000/day. • New-build FSRUs will command $100-110,000/day. • Typical breakdown of OPEX into the key components is shown in the next slide. • Tax costs are generally project specific and passed through to the charterer. • Low side rates reflect distressed charters where an owner has failed to place a vessel within a reasonable time period, or it is trading as an LNGC. • High rates reflect a distressed hirer or extension of an earlier higher-priced charter. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Since 2015, the range has been between 2 and 27 years. • Initial periods with extension options that provide charterers with the flexibility to respond to changing market circumstances. • Alternative option is to trade at a much-reduced rate in the LNGC market |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Staffing (crew) costs: benchmarked from similar projects • Maintenance: benchmarked from similar projects • Management: benchmarked from similar projects • Surveys: benchmarked from similar projects • Insurance: benchmarked from similar projects • Consumables: benchmarked from similar projects • Lube, Paint, Chemicals: benchmarked from similar projects • LNG as fuel consumption varies with the gas send-out and is estimated to be around 0.35%. For a tolling facility, this will be incorporated into the TUA terms • Towage costs may only be partially recovered from incoming LNG carriers and may need to be supported by the terminal operator • If the FSRU is traded as an LNGC, charterer will be responsible for fuel and port costs |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Crew and Manning: The crew required to operate and maintain the FSRU. • Maintenance and repair: Cost to maintain the FSRU as well as the ship engines, electrical power generators, water intake pump and the hull. • Insurance: Protection and indemnity insurance for the FSRU (Hull and equipment). • Other: Consumables/stores, maintenance & repair, spare parts, other operating agreement costs (not covered in OPEX items above). They are very small in comparison. • The inflation is usually agreed during the charter signing and is either a fixed percentage or linked to an index such as the US CPI |
© POTEN & PARTNERS 2009 CONFIDENTIAL • FSRU storage and sendout capacity • FSRU technology and systems such as open-loop, closed-loop, combined loop regasification • Charter duration and timeline • Market supply demand and availability of charters • Also (with the exception of Bahrain Spirit) more likely to be a much older vessel. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Impact of this is that planned projects won’t/can’t go ahead within their proposed schedules. • In practice, we believe CAPEX charter rates may have been closer to $120,000/d - $130,000/d. • Spare vessels are limited - only a few ships are available and only three could be released from contracts this year. • The earliest delivery for a newbuild is likely to be 2026 or conversion by end 2023. • They will have to get Class and Flag state approval for no dockings in this time which means thorough docking (and any modifications necessary) for new role. • Lost charter revenue and docking costs >$15 million - $20 million depending on work carried out and age of vessel. |
CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.
© POTEN & PARTNERS 2009 CONFIDENTIAL • However, timing is an issue… If Lampung upgrade were to take 24 months, HMLP may lose market opportunity. • If Lampung charter is terminated in November 2022 based on arbitration outcome, HMLP may not know until close to that time - not much time for engineering study for new charter/location. • N.B. A potential charterer in a hurry could take the vessel without modification, if desperate. • At the lower end, it could be $ - $ as over 50% depreciated by that time. • Shipowners unlikely to convert to FSRU on speculative basis, only against a specific project requirement. |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Two 174,000m3 newbuilds owned by Dynagas: Transgas Power and Transgas Force. They have both been chartered to Uniper for use as FSRUs in Germany once they come off their LNGC charters. • A 145,000m3 newbuild owned by Höegh LNG, MOL and TG, Neptune, remains under charter to Total. Total now states that Neptune will be used for an FSRU in Europe. • N.B. Cape Ann operates as an FSRU in Tianjing and also trades part of the year as an LNGC. • BW Paris: Not clear what it is doing at the moment, and if the Egypt project or BW is responsible for chartering out. • BW Tatiana has just started FSRU operations in El Salvador. • Höegh Giant and Vasant: under charter to H-Energy (India) who was out on short-term charters waiting for start-up. Will not be charterered out long-term. • Höegh Gannet: Dedicated for Brazil or Australia, which ever one firms up first. Not available for long-term charter. • MOL Challenger: If not already in drydocking to prepare for the Hong Kong project (summer start-up), then it will be. • Exemplar: Excelerate is short on details for their fleet. They claim all vessels are dedicated to projects, but don’t know when the start-ups are or when. So it’s probably being used as an LNGC for the moment. • Drydocking every 2.5 years if the vessel is over 15 years old, and every 5 years if the vessel is less than 15 years old. – Höegh have exemptions on some vessels for 7.5 years between dockings. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • Ship capacity is normalized to 174,000m3 -the current standard size for an LNGC. • Poten’s forecast is LNG demand driven. Annual LNG demand is forecast on a country-by-country basis. Volumes under firm contract are subtracted to yield unfilled LNG demand for each country; • Annual global LNG supply is based on Poten’s forecast of annual LNG production from existing projects, expansions and from new projects. From this production forecast, contracted LNG sales are subtracted to yield uncommitted LNG; • Uncommitted LNG supply is matched with unfilled demand for each year. Thus, explicit trade routes and annual ship requirements are defined for both contracted LNG quantities and short-term sales; • The ship demand/requirement is the number of ships required to serve LNG trade. The annual ship requirement is calculated for every SPA. Ship requirements are also calculated for spot trades. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • This is equivalent to around 730 ships when normalized to 174,000m3. • N.B. this excludes floating LNG vessels and small / medium-scale LNG vessels. • Includes existing ships and firm orders only - does not include projections / options to build new ships; • Vessels >35 years old are not included – vessels are scrapped / laid up / converted (22 vessels by 2030). • Global fleet utilisation rate of 80% • Capacities are normalised to 174,000 m3 • However, new ships will still be ordered; depending on how much existing undedicated capacity is utilized and whether projects start up as scheduled. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • This is equivalent to around 730 ships when normalized to 174,000m3. • N.B. this excludes floating LNG vessels and small / medium-scale LNG vessels. • Includes existing ships and firm orders only - does not include projections / options to build new ships; • Vessels >35 years old are not included – vessels are scrapped / laid up / converted (22 vessels by 2030). • Global fleet utilisation rate of 80% • Capacities are normalised to 174,000 m3 • However, new ships will still be ordered; depending on how much existing undedicated capacity is utilized and whether projects start up as scheduled. |
© POTEN & PARTNERS 2009 CONFIDENTIAL • This is equivalent to around 730 ships when normalized to 174,000m3. • N.B. this excludes floating LNG vessels and small / medium-scale LNG vessels. • Includes existing ships and firm orders only - does not include projections / options to build new ships; • Vessels >30 years old are not included – vessels are scrapped / laid up / converted (49 vessels by 2030). • Global fleet utilisation rate of 80% • Capacities are normalised to 174,000 m3 • However, new ships will still be ordered; depending on how much existing undedicated capacity is utilized and whether projects start up as scheduled. |
© POTEN & PARTNERS 2009 CONFIDENTIAL |
© POTEN & PARTNERS 2009 CONFIDENTIAL • There has been a large number of LNG vessel orders placed recently, due to be delivered by 2025. • FSRU owners do not want to have to trade in LNGC market and get lower return in early life of vessel. • Newbuild construction time of ~ 3 years. A A A A ART RT RT RT RTNE NE NE NE NERS RS RS RS RS 200 00 00 0 009 9 9 9 9 |
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© POTEN & PARTNERS 2009 CONFIDENTIAL N&PA RT T T TN N NE N N RS 2009 N N N & & & & & PA PA PA PA PART RT RT RT RTNE N NE NE NERS RS RS RS RS 2 2 2 2 20 ID D D DEN EN EN ENTI TI TI T AL AL AL AL AL |
Exhibit 107
Calculation of Filing Fee Table
Table 1 - Transaction Valuation
Transaction valuation | Fee Rate | Amount of Filing Fee | ||||||||||
Fees to Be Paid | $ | 167,568,412.00 | (1) | 0.0000927 | $ | 15,533.59 | (2) | |||||
Fees Previously Paid | — | $ | — | |||||||||
Total Transaction Valuation | $ | 167,568,412.00 | ||||||||||
Total Fees Due for Filing | $ | 15,533.59 | ||||||||||
Total Fees Previously Paid | — | |||||||||||
Total Fee Offsets | — | |||||||||||
Net Fee Due | $ | 15,533.59 |
Table 2 – Fee Offset Claims and Sources
Registrant or Filer Name |
Form or Filing Type |
File Number |
Initial Filing Date |
Filing Date |
Fee Offset Claimed |
Fee Paid with Fee Offset Source |
||||||||||||
Fee Offset Claims | ||||||||||||||||||
Fee Offset Sources |
(1) | For purposes of calculating the fee only, this amount is based upon the sum of (a) 18,115,504 common units representing limited partner interests (“Common Units”) of Höegh LNG Partners LP subject to the transaction, multiplied by $9.25 per Common Unit. |
(2) | The amount of the filing fee, calculated in accordance with Exchange Act Rule 0-11(b)(1) and the Securities and Exchange Commission Fee Rate Advisory #1 for Fiscal Year 2022, was calculated by multiplying $167,568,412.00 by 0.0000927. |