October 2023 Company Update
2 Focused on growing volumes in markets where NFE is already operational, requiring minimal additional capex(1) Executive Summary NFE is a $10bn+ leading LNG infrastructure company with long-term, diversified & stable cash flows Earnings underpinned by long-term contracts 12yrs avg. contract duration ~75% of ‘24 AEBITDA from IG counterparties(4) La Paz Mexico Puerto Sandino Nicaragua San Juan Puerto Rico Old Harbour Jamaica Montego Bay Jamaica Barcarena Brazil Jamalco CHP Jamaica Santa Catarina Brazil Miami Liquefier USA Power plant Terminals & facilities under development Terminals & facilities in operation Fast LNG 2021 2022 2023 2024 Terminal Volumes TBtu 55 49 88 158 Cargo Sales TBtu 20 39 48 27 Total Volumes TBtu 74 88 136 185 Adj. EBITDA(2) $mm $605 $1,071 ~$1,600 ~$2,400 Large portfolio of critical & irreplaceable energy infrastructure Illustrative Goals(3)Historical Robust terminal volumes & earnings growth
Executive Summary Our earnings are increasing significantly in both size & quality Formula 2021 2022 2023 2024 Historical ($mm) Illustrative Goals(3) ($mm) Terminals (gas & power) $235 $218 ~$850 ~$2,200 (+) Cargo Sales (inclusive of cargo vessels) $246 $676 ~$650 ~$150 (+) Ships $266 $356 ~$250 ~$200 (-) Core SG&A ($142) ($179) (~$175) (~$175) Adj. EBITDA(2) $605 $1,071 ~$1,600 ~$2,400 3 Material growth in core terminal earnings with Puerto Rico expansion & Brazil coming online(5) Terminal operating margin Downstream terminal earnings targeted to increase ~10x as our infrastructure comes online(5) • Focus is on long-term downstream customer earnings • Expect terminal earnings to grow from ~$850mm this year to ~$2.2bn next year(3)
4 Executive Summary While our earnings have grown significantly, we believe that measure alone significantly understates the value of our business The value of our company is generated by 3 main components: + + Value of Infrastructure Assets Value of Forward Customer Contracted Margin (FCCM) Value of Surplus Terminal Capacity “Forward customer contracted margin”, or “FCCM”, typically refers to the expected profit or margin a company anticipates earning from customer contracts in the future. It’s the projected financial gain a business estimates it will receive based on existing contractual agreements with customers.
5 Executive Summary Infrastructure Terminals(6) 7 Jamaica (Montego Bay & Old Harbour) Mexico (La Paz) Nicaragua (Puerto Sandino) Puerto Rico (San Juan) Brazil (Barcarena & Santa Catarina) MW from power plants(7) ~6000 Puerto Rico (San Juan, Palo Seco & PREPA assets) Brazil (Barcarena) Nicaragua (Puerto Sandino) Mexico (La Paz) Jamaica (Jamalco) 8 FSRUs 6 Storage 6 Transports 3 OSVs 10 FLNG vessels 4 Support vessels Liquefiers(9) 3 USA (Miami) Mexico (Fast LNG 1 ) Mexico (Fast LNG 2) Ships(8) 37 Our mission is to deliver cleaner, cheaper gas & power to customers around the world To deliver on our mission, we have built or purchased ~$7.5bn in infrastructure in the last 9 years
30 TBtu x ($2.50) 6 Executive Summary Forward Customer Contracted Margin (FCCM)(10) Our Illustrative FCCM Goals are based on long-term gas and power contracts, averaging 12 years in duration 1. We provide gas or power to customers through our terminals 2. We provide all logistics & mobility 3. We collect a long- term spread with little commodity risk Our business is simple Illustrative assumptions for one contract: Volume 30 TBtu Term 15 years Avg. terminal & mobility costs $1.00/MMBtu Customer contract price HH x 115% + $6.00/MMBtu Avg. portfolio cost of gas HH x 115% + $2.50/MMBtu 30 TBtu x ($6.00 - $2.50 - $1.00) $75mm/yr for 15 years = = volume x (revenue – gas cost – logistics/terminals costs) How we calculate the value of our targeted FCCM– an illustrative example:
$1.8 $2.5 $2.5 $6.7 $10.2 $11.6 $11.7 $13.6 - $2.0bn $4.0bn $6.0bn $8.0bn $10.0bn $12.0bn $14.0bn $16.0bn 2016 2017 2018 2019 2020 2021 2022 2023 Barcarena Nicaragua Puerto Rico La Paz Old Harbour Montego Bay Miami 7 Executive Summary The targeted value of our FCCM could exceed $13bn(10) 2016A 2017A 2018A 2019A 2020A 2021A 2022A 2023F Goal Contracted Terminals 3 3 4 6 7 7 7 7 Volumes (TBtu) - 8 8 17 18 74 88 136 Value of FCCM ($bn) $1.8bn $2.5bn $2.5bn $6.7bn $10.2bn $11.6bn $11.7bn $13.6bn FCCM has grown ~33% annually over the past 8 years 33% CAGR
Estimated capacity(12) Terminal capacity Executive Summary 8 At current contracted volumes, we use ~24% of our capacity Our 7 terminals, all of which will be online in 2024, allow us to bring gas to countries around the world How to calculate terminal capacity(11) Storage at terminal x frequency it can be refilled Example: = ~6 MTPA of capacity Storage capacity 3 TBtu (~150 m3) Weekly refill frequency 2 times 52 weeks x x TBtu MTPA Montego Bay 20 0.4 Old Harbour 150 3.0 Puerto Rico (Current)(i) 65 1.3 Barcarena 300 5.9 Santa Catarina 300 5.9 Mexico 150 3.0 Nicaragua 150 3.0 Total 1,135 22.5 2022 2023 2024 2025 88 136 185 269 Rule of thumb: ~50 TBtu = 1mm tonnes Projected utilization with contracted volumes (TBtu)(12) i. Current capacity. Puerto Rico Increased Capacity adds 235 TBtu or 4.6 MTPA for a total of 300 TBtu or 5.9 MTPA.
9 Executive Summary In sum, NFE is a stable & rapidly growing business with expected Free Cash Flow(13) of ~$1.8bn in 2024 2021 2022 2023 2024 Adj. EBITDA(2) $mm $605 $1,071 ~$1,600 ~$2,400 Free Cash Flow(13) $mm $195 $337 ~$1,000 ~$1,800 Capex(1) $mm $669 $1,174 ~$2,100 ~$400 + + Value of Forward Customer Contracted Margin (FCCM)(10) ~$13.6bn Additional Growth Through surplus capacity at existing terminals Value of Infrastructure Assets ~$7.5bn Illustrative Goals(1)(3)(14) Capital expenditures are expected to greatly decrease as a result of developments (FLNG 1, Puerto Rico, etc.) being completed
Capital plan 10 Executive Summary Financing Planned financings targeted to raise $400mm+ of new capital which will enable us to fully fund FLNG 2’s capex(1) + Earnings & asset sales Between now and the end of 2024, we expect to generate ~$2.5-3.0bn in free cash flow(20) Rapid deleveraging We will use these proceeds to deleverage our balance sheet and target an investment grade rating
11 Project Updates Project/infrastructure updates We have a number of significant projects that are at or near completion Project Expected COD(21) Description Puerto Rico Power COD achieved 350-400 MW of gas-fired FEMA power (150 MW at Palo Seco, 200-250 MW at San Juan) located near & supplied by our San Juan LNG terminal La Paz, Mexico Power COD achieved 135 MW gas-fired power plant located at our La Paz LNG terminal; provides power to Baja California Sur’s grid FLNG 1, Mexico Nov. 2023 1.4 MTPA liquefaction facility located offshore Altamira, Mexico; receives gas from the Sur de Texas-Tuxpan pipeline & liquefies it for export Barcarena, Brazil Dec. 2023 6 MTPA LNG terminal located at the mouth of the Amazon river; 624 MW power plant also under construction with COD(21) in 2025 Santa Catarina, Brazil Jan. 2024 6 MTPA LNG terminal located in southern Brazil; will be connected to existing gas distribution pipeline
Our subsidiary, GeneraPR, took over PREPA operations with a 10-year contract 12 Project Updates 350-400 MW of FEMA power recently online in Puerto Rico Through our San Juan facility, 2 power installations & subsidiary GeneraPR, we manage majority of the island’s generation assets Commissioned after Hurricane Maria devastated the island in 2017 300 MW gas supply deal with PREPA San Juan Facility Commercial operations: Q3 2020 Capacity: 3 MTPA Commissioned after FEMA issued RFP for emergency power installation NFE won RFP to supply all turbines & gas for 2 years Palo Seco Power Commercial operations: Q2 2023 Capacity: 150 MW Commissioned after FEMA issued RFP for emergency power installation NFE won RFP to supply all turbines & gas for 2 years San Juan Power Commercial operations: Q3 2023 Capacity: 200-250 MW 17 sites 4,693 MW capacity 700 employees 1.5mm customers Insert map of PREPA assets San Sebastian Victoria Añasco Mayaguez Planta Caonillas Dos Bocas Hatillo Barceloneta Vega BajaDorado Toro Negro Juana Diaz Pattern Wind Farm BarranquitasComerio Viaducto Hato Rey Isla Grande G.I.S. AcaciasSan German Guanica Canas Santa Isabel Jobos Maunabo Shell Cayey CaguasJuncos Humacao Daguao Rio Blanco Palmer Fajardo Canovan s Martin PenaBerwind Ponce Monacillos NFE built & operated assets GeneraPR operated assets
Provides much needed cleaner & more reliable energy to the grid 13 Project Updates 135 MW La Paz, Mexico power plant now online Agreement to sell plant to CFE (Mexico’s power utility) in 2024, further enhancing NFE’s ability to internally fund strategic growth initiatives that service our customers’ needs Achieved COD in September 2023
FLNG 1 consists of 3 platforms (all onsite in Altamira) 14 Project Updates FLNG 1 is installed & connected to gas Platform I Function: Gas treatment Platform II Function: Liquefaction Platform III Function: Utilities All three modules arrived onsite First Gas expected October(22) First LNG expected November (22) 1.4 MTPA FLNG 1’s rapid deployment provides incremental LNG supply to fulfil our downstream needs production volume
15 Project Updates FLNG 2 already under construction & expected to be deployed onshore Altamira World-class import terminal with nearly 100% expected reliability has everything needed to quickly convert into an export facility Area map 14-meter berth pocket 300k m3 of storage 2 GW+ from 3 power plants Electrical substation MMcf/d feedgas from Texas200 MTPA1.4 million capital cost$900 Plan to install 1.4 MTPA liquefaction train on this land Total capex(1) $900mm Sources: Money spent to date $300mm Proceeds from planned financings $400mm+ Free Cash Flow $200mm Total Sources $900mm online date(21)2025 Signed LOI with CFE to develop onshore Altamira site Transforming Altamira into an export terminal follows the legacy of Sabine Pass nearly 10 years ago
High-volume Brazil terminals coming online Project Updates 16 Barcarena Vast amount of organic growth potential from Brazil projects coming online this year(21) NTS Pipeline TAG Pipeline TBG Pipeline Expected Demand: 3-5 MTPA • Norsk Hydro (BBB/Ba3) serves as anchor customer with 15-year GSA • Sole natural gas supply source in region • Margin profile similar to other NFE terminals with ~4-5 xgreater volume potential • 624 MW power plant under construction; 25-year PPA starting 2025 generating significant fixed revenue Barcarena • High volume terminal with vast margin potential • Connected pipeline supports incremental volume sales with no capex(1) requirement • Takes advantage of declining gas imports from Bolivia & oil-derivative fuels for “stranded” demand Santa Catarina Expected Demand: 3-5 MTPA Santa Catarina
17 Disciplined financial policy supports deleveraging Financial Policy Stable dividend policy(23) Disciplined capital management Expect extensive deleveraging • Confirming $0.10 per share quarterly dividends • No special dividends expected going forward • 2024 capex(1) & remaining FLNG projects will be fully funded(24) by the planned financings • Targeting leverage of <2.0x for YE 2024(3) • Non-core asset sales of ~$1bn used to repay balance of 2025 maturities(20) • Terminal cash flows used to pay down revolver(20) NFE has transitioned into a mature company with growing & stable cash flows to support a disciplined financial policy
18 Appendix
19 Appendix - Company & Asset Overview Step 3: Operate ships & logistics assets to deliver LNG to our terminals & power plants Step 2: Source LNG from the market & our own liquefaction facilities Step 1: Build LNG import terminals & power assets Step 4: Sell gas and power to our downstream customers We identify places around the world where affordable, reliable, cleaner energy is in short supply and deliver the solution How our business works
NFE’s path to becoming a global, integrated LNG infrastructure player Appendix - Company & Asset Overview 20 NFE founded 2014 First LNG at Miami Liquefier 2015 Export first LNG from the U.S. to a non-FTA country First Gas at Montego Bay 2016 Initial Public Offering on January 31 First Gas at Old Harbour 2019 First Gas at Jamalco First Gas at San Juan Zero is established 2020 Hygo acquisition GMLP acquisition First Gas at La Paz 2021 Sold 50% stake in Sergipe power plant for ~$1.3bn Formed ~$2bn JV with Apollo to sell and charter-back LNG vessels Commenced construction on Barcarena power plant 2022 Created GeneraPR Signed Palo Seco (150 MW) power contract Signed San Juan (200 MW) power contract FLNG 1 First LNG in November(22) Barcarena Terminal COD in December(21) 2023 Santa Catarina COD in January(21) 2024
Marked the beginning of Jamaica’s energy diversification 21 Appendix - Company & Asset Overview Montego Bay (Jamaica) Facility Ship-to-shore with landed storage and truck loading facility Capacity 0.4 Mtpa Function Supply natural gas to the 145MW Bogue Power Plant operated by Jamaica Public Service Company & other industrial customers Commercial Operations Q4 2016
Serving as a regional hub for LNG distribution in the Caribbean 22 Appendix - Company & Asset Overview Old Harbour (Jamaica) Facility FSRU and associated infrastructure & power plant Capacity 3 MTPA (FSRU) | 150 MW (power plant) Function Supply gas to the 190MW Old Harbour Power Plant owned & operated by South Jamaica Power Company and NFE CHP Power Plant Commercial Operations Q2 2019 (FSRU) Q1 2020 (power plant)
Bringing cleaner energy to Puerto Rico 23 Appendix - Company & Asset Overview San Juan (Puerto Rico) Facility Onshore micro-fuel handling facility Capacity 1.3 MTPA Function Supply LNG to on-island industrial users and natural gas to the PRERA San Juan Power Plant owned and operated by Puerto Rico Electric Power Authority Commercial Operations Q3 2020
Supplying the Amazon river basin with cleaner energy Appendix - Company & Asset Overview Barcarena (Brazil) Facility FSRU and associated infrastructure & power plant Capacity 5.9 MTPA (FSRU) | 624 MW (power plant) Function Supply gas to Alunorte Alumina Refinery owend by Norsk Hydro ASA and NFE Barcarena Power Plant Commercial Operations(21) 4Q 2023 (FSRU) 2025 (power plant) 24
Bringing LNG to southern Brazil 25 Appendix - Company & Asset Overview Santa Catarina (Brazil) Facility FSRU and associated infrastructure Capacity 5.9 MTPA Function Supply gas into the local power and industrial markets and be connected to existing inland Transportadora Brasileria Gasoduto Bolivia-Brasil pipeline Commercial Operations(21) 1Q 2024
26 Powering La Paz with positive energy Appendix - Company & Asset Overview La Paz (Mexico) Facility Onshore LNG receiving facility & power plant Capacity 3 MTPA (LNG facility) | 100 MW (power plant) Function Supply LNG to multiple CFE power generation facilities and NFE La Paz power Plant Commercial Operations Q2 2021 (LNG facility) Q3 2023 (power plant)
27 Supporting more consistent power in Nicaragua Appendix - Company & Asset Overview Puerto Sandino (Nicaragua) Facility FSRU and associated infrastructure & power plant Capacity 3 MTPA (FSRU) | 300MW (power plant) Function Supply natural gas to NFE Puerto Sandino Power Plant in connection with a 25-year PPA with Nicaragua’s electricity distribution companies Commercial Operations(21) 2024
Appendix Adjusted EBITDA 28 (in thousands of U.S. dollars) FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 Net income $(32,926) $(31,671) $(78,076) $(204,319) $(263,965) $92,711 $184,786 Add: Interest expense 5,105 6,456 11,248 19,412 65,723 154,324 236,861 Add: Tax provision (benefit) (361) 526 (338) 439 4,817 12,461 (123,439) Add: Contract termination charges and loss on mitigation sales — — — 5,280 124,114 — — Add: Depreciation and amortization 2,341 2,761 3,321 7,940 32,376 98,377 142,640 Add: Asset impairment expense — — — — — — 50,659 Add: SG&A items excluded from Core SG&A — — — 58,789 28,162 62,737 61,640 Add: Transaction and integration costs — — — — 4,028 44,671 21,796 Add: Other (income) expense, net (53) (301) (784) (2,807) 5,005 (17,150) (48,044) Add: Changes in fair value of non-hedge derivative instruments and contingent consideration — — — — — 2,788 (103,490) Add: Loss on extinguishment of debt, net 1,177 — 9,568 — 33,062 10,975 14,997 Add: Pro rata share of Adjusted EBITDA from unconsolidated entities — — — — — 157,109 160,684 Less: Loss (income) from equity method investments — — — — — (14,443) 472,219 Add: Contract acquisition cost — — — — — — — Adjusted EBITDA (non-GAAP) $(24,717) $(22,229) $(55,061) $(115,266) $33,322 $604,560 $1,071,309
Appendix Adjusted EBITDA 29 (in thousands of U.S. dollars) FY 2019 FY 2020 FY 2021 FY 2022 Total Selling, general and administrative $152,922 $120,142 $199,881 $236,050 Core SG&A 94,133 91,980 137,144 174,410 SG&A items excluded from Core SG&A 58,789 28,162 62,737 61,640
Segment operating margin reconciliation 30 Appendix (in thousands of $) Terminals and Infrastructure (1) Ships (2) Total Segment Consolidation and Other (3) Consolidated Total revenues 1,366,142 329,608 1,695,750 (372,940) 1,322,810 Cost of sales 789,069 - 789,069 (173,059) 616,010 Vessel operating expenses 3,442 64,385 67,827 (16,150) 51,677 Operations and maintenance 92,424 - 92,424 (19,108) 73,316 Consolidated Segment Operating Margin 481,207 265,223 746,430 (164,623) 581,807 Less: Selling, general and administrative 199,881 Transaction and integration costs 44,671 Depreciation and amortization 98,377 Interest expense 154,324 Other (income), net (17,150) Tax provision 12,461 Loss from extinguishment of debt 10,975 (Income) from equity method investments (14,443) Net income 92,711 Year Ended December 31, 2021 ⁽¹⁾ Terminals and Infrastructure includes the Company's effective share of revenues, expenses and operating margin attributable to 50% ownership of CELSEPAR. The losses attributable to the investment of $17,925 for the year ended December 31, 2021 are reported in income from equity method investments on the consolidated statements of operations and comprehensive income (loss). Terminals and Infrastructure does not include the unrealized mark-to-market loss on derivative instruments of $2,788 for the year ended December 31, 2021 reported in Cost of sales. ⁽²⁾ Ships includes the Company's effective share of revenues, expenses and operating margin attributable to 50% ownership of the Hilli Common Units. The earnings attributable to the investment of $32,368 for the year ended December 31, 2021 are reported in income from equity method investments on the condensed consolidated statements of operations and comprehensive income (loss) ⁽³⁾ Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to 50% ownership of CELSEPAR and Hilli Common Units in our segment measure and exclusion of the unrealized mark-to-market gain or loss on derivative instruments.
Appendix Segment operating margin reconciliation 31 Year Ended December 31, 2022 (in thousands of $) Terminals and Infrastructure (1) Ships (2) Total Segment Consolidation and Other (3) Consolidated Total revenues 2,168,565 444,616 2,613,181 (244,909) 2,368,272 Cost of sales 1,142,374 — 1,142,374 (131,946) 1,010,428 Vessel operating expenses — 90,544 90,544 (27,026) 63,518 Operations and maintenance 129,970 — 129,970 (24,170) 105,800 Consolidated Segment Operating Margin 896,221 354,072 1,250,293 (61,767) 1,188,526 Less: Selling, general and administrative 236,051 Transaction and integration costs 21,796 Depreciation and amortization 142,640 Asset impairment expense 50,659 Interest expense 236,861 Other (income), net (48,044) Loss from extinguishment of debt, net 14,997 Loss from equity method investments 472,219 Tax (benefit) (123,439) Net income 184,786 ⁽¹⁾ Prior to the completion of the Sergipe Sale, Terminals and Infrastructure included the Company's effective share of revenues, expenses and operating margin attributable to 50% ownership of CELSEPAR. The loss attributable to the investment of $397,874 for the year ended December 31, 2022 are reported in (Loss) income from equity method investments on the consolidated statements of operations and comprehensive income (loss). Terminals and Infrastructure does not include the unrealized mark-to-market loss on derivative instruments of $106,103 for the year ended December 31, 2022 reported in Cost of sales. ⁽²⁾ Ships includes the Company's effective share of revenues, expenses and operating margin attributable to 50% ownership of the Hilli Common Units. The earnings attributable to the investment of $77,132 for the year ended December 31, 2022 are reported in (Loss) income from equity method investments on the consolidated statements of operations and comprehensive income (loss). ⁽³⁾ Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to 50% ownership of CELSEPAR and Hilli Common Units in our segment measure and exclusion of the unrealized mark-to-market gain or loss on derivative instruments.
Free cash flow reconciliation 32 Appendix (in thousands of U.S. dollars) FY 2021 FY 2022 Net (loss) income attributable to stockholders 97,104 194,479 Depreciation and amortization 98,377 142,640 Free cash flow (Non-GAAP) 195,481 337,119
Adjusted Net Income and Adjusted EPS 33 Appendix (in thousands of U.S. dollars except for share amounts) FY 2021 FY 2022 Net income attributable to stockholders (GAAP) 97,104 194,479 Non-cash impairment charges, net of tax — 381,302 Loss on disposal of investment in Hilli LLC — — Adjusted net income (Non-GAAP) 97,104 575,781 Weighted-average shares outstanding - diluted 201,703,176 209,854,413 Adjusted earnings per share – diluted 0.47 2.74
34 Disclaimers IN GENERAL. This disclaimer applies to this document and the verbal or written comments of any person presenting it. This document, taken together with any such verbal or written comments, is referred to herein as the “Presentation.” FORWARD-LOOKING STATEMENTS: All statements contained in this Presentation other than historical information are forward-looking statements that involve known and unknown risks and relate to future events, our future performance or our projected results. You can identify these forward-looking statements by the use of forward-looking words such as “expects,” “may,” “will,” “can,” “could,” “should,” “predicts,” “intends,” “plans,” “estimates,” “anticipates,” “believes,” “schedules,” “progress,” “targets,” “budgets,” “outlook,” “trends,” “forecasts,” “projects,” “guidance,” “focus,” “on track,” “goals,” “objectives,” “strategies,” “opportunities,” “poised,” or the negative version of these terms or other comparable words. Forward looking statements include but are not limited to: illustrative financial metrics and other similar metrics, including goals and expected financial growth, among others; our expected terminal volumes and earnings growth at our terminals in future years; our ability to achieve Guidance including our Estimated Total Volumes, including Terminal Volumes and Cargo Sales and our Illustrative Adjusted EBITDA Goals; our ability to achieve our goal related to our 2024 Illustrative Adjusted EBITDA from Investment Grade customers; the successful development, construction, completion, operation and/or deployment of facilities, including our FLNG, Brazil, Nicaragua and Puerto Rico projects, on time, within budget and within the expected specifications, capacity and design; our ability to achieve our Illustrative Customer Contracted Margin Goal at the end of 2023; our ability to bring the rest of our terminals online in 2024, as well as meet our capacity goals and expected utilization goals at the terminals; our ability to achieve our Illustrative Goals related to adjusted earnings per share, free cash flow and adjusted net income, including through additional growth from the surplus capacity at our existing terminals, our ability to execute our Capital Plan, including the closing of planned financings on acceptable terms, the Company’s ability to (i) achieve the Illustrative Free Cash Flow Goals, (ii) potentially repurchase, redeem or otherwise acquire part of the Senior Secured 2025 Notes and paydown the Revolving Credit Facility, and (iii) complete targeted Asset Sales of approximately $1.0 billion in the next 12 months, our ability to achieve an improved leverage ratio at the end of 2024 and achieve an Investment Grade credit rating, the projected total capital expenditures for our FLNG 2 Project as well as the installation plans and timing, the amount and payment of the Company’s quarterly dividend; and future strategic plans. These forward-looking statements are necessarily estimates based upon current information and involve a number of risks, uncertainties and other factors, many of which are outside of the Company’s control. Actual results or events may differ materially from the results anticipated in these forward-looking statements. Specific factors that could cause actual results to differ from those in the forward- looking statements include, but are not limited to: failure to implement our business strategy as expected; risks related to the development, construction, commissioning and completion of facilities, including cost overruns and delays; failure to convert our customer pipeline into actual sales; risks related to the operation and maintenance of our facilities and assets; risks related to the operation and maintenance of our facilities and assets; failure of our third party contractors, equipment manufacturers, suppliers and operators to perform their obligations for the development, construction and operation of our projects, vessels and assets; the risk that the proposed transactions may not be completed in a timely manner or at all, including the risk that the proposed planned financings cannot be executed due to market conditions and/or the Company’s ability to negotiate acceptable terms; risks related to the Company’s proposed Asset Sales, including whether a market will develop for such assets and whether the Company will be able to agree to acceptable pricing and other terms offered by potential buyers; risks related to the approval and execution of definitive documentation; inability to successfully develop and implement our technological solutions, including our Fast LNG technology, or that we do not receive the benefits we expect from the Fast LNG technology; cyclical or other changes in the LNG and natural gas industries; competition in the energy industry; the receipt of permits, approvals and authorizations from governmental and regulatory agencies on a timely basis or at all; new, or changes to, existing governmental policies, laws, rules or regulations, or the administration thereof; failure to maintain sufficient working capital and to generate revenues, which could adversely affect our ability to fund our projects; adverse regional, national, or international economic conditions, adverse capital market conditions and adverse political developments; and the impact of public health crises, such as pandemics and epidemics and any related company or government policies and actions to protect the health and safety of individuals or government policies or actions to maintain the functioning of national or global economies and markets.
35 Disclaimers FORWARD-LOOKING STATEMENTS (con’t.). These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of the Company’s forward-looking statements. Other known or unpredictable factors could also have material adverse effects on future results. Any forward-looking statement speak only as of the date on which it is made, and we undertake no duty to update or revise any forward-looking statements, even though our situation may change in the future or we may become aware of new or updated information relating to such forward-looking statements. New factors emerge from time to time, and it is not possible for the Company to predict all such factors. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements included in New Fortress Energy Inc.’s annual and quarterly reports filed with the Securities and Exchange Commission, which could cause its actual results to differ materially from those contained in any forward-looking statement. PAST PERFORMANCE. Our operating history is limited and our past performance is not a reliable indicator or indicative of future results and should not be relied upon for any reason. There can be no assurance that the future performance of the Company, or any project, investment or asset of the Company, will be profitable or equal any corresponding indicated historical performance level(s). ILLUSTRATIVE ECONOMICS. Illustrative economics are hypothetical values based on specified assumptions that are aspirational in nature rather than management’s view of projected results. Actual results could differ materially and the hypothetical assumptions on which this illustrative data is based are subject to numerous risks and uncertainties.
Endnotes 36 1. For the periods ending December 31, 2021 and 2022, Capex reflects the amounts presented in the Company’s 2022 Form 10-K. For future periods, Capex reflects management’s estimate of total expected cash payments in such period less cash proceeds received by the Company for related asset sales or direct asset financings. Investors are encouraged to review the related GAAP financial measures, and not to rely on any single financial measure to evaluate our business. 2. “Adjusted EBITDA” is not a measurement of financial performance under GAAP and should not be considered in isolation or as an alternative to income from operations, net income, cash flow from operating activities or any other measure of performance or liquidity derived in accordance with GAAP. We believe this non-GAAP measure, as we have defined it, offers a useful supplemental view of the overall operation of our business in evaluating the effectiveness of our ongoing operating performance in a manner that is consistent with metrics used for management’s evaluation of the Company’s overall performance and to compensate employees. We believe that Adjusted EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation, and amortization which vary substantially from company to company depending on capital structure, the method by which assets were acquired and depreciation policies. Further, we exclude certain items from our SG&A not otherwise indicative of ongoing performance. We calculate Adjusted EBITDA as net income, plus transaction and integration costs, contract termination charges and loss on mitigations sales, depreciation and amortization, asset impairment expense, interest expense (net), other expense (income), net, loss on extinguishment of debt, changes in fair value of non-hedge derivative instruments and contingent consideration, tax expense, and adjusting for certain items from our SG&A not otherwise indicative of ongoing operating performance, including non-cash share-based compensation and severance expense, non-capitalizable development expenses, cost to pursue new business opportunities and expenses associated with changes to our corporate structure, plus our pro rata share of Adjusted EBITDA from certain unconsolidated entities, less the impact of equity in earnings (losses) of certain unconsolidated entities plus certain non-capitalizable contract acquisition costs. Adjusted EBITDA is mathematically equivalent to our Total Segment Operating Margin, as reported in the segment disclosures within our financial statements, minus Core SG&A, including our pro rata share of such expenses of certain unconsolidated entities. Core SG&A is defined as total SG&A adjusted for non-cash share-based compensation and severance expense, non-capitalizable development expenses, cost to pursue new business opportunities and expenses associated with changes to our corporate structure. Core SG&A excludes certain items from our SG&A not otherwise indicative of ongoing operating performance. The principal limitation of Adjusted EBITDA is that it excludes significant expenses and income that are required by GAAP to be recorded in our financial statements. Investors are encouraged to review the related GAAP financial measures and the reconciliation of Adjusted EBITDA to our GAAP net income, and not to rely on any single financial measure to evaluate our business. Adjusted EBITDA does not have a standardized meaning, and different companies may use different Adjusted EBITDA definitions. Therefore, Adjusted EBITDA may not be necessarily comparable to similarly titled measures reported by other companies. Moreover, our definition of Adjusted EBITDA may not necessarily be the same as those we use for purposes of establishing covenant compliance under our financing agreements or for other purposes. Adjusted EBITDA should not be construed as alternatives to net income and diluted earnings per share attributable to New Fortress Energy, which are determined in accordance with GAAP. 3. Leverage goal of 2.0 times 2024 Adjusted EBITDA is a forward-looking statement that represents management’s current goal to achieve a reduced leverage by the end of fiscal 2024 by executing the company’s business strategy with the pro forma capital plan in place. “Illustrative Adjusted EBITDA Goal” means our forward-looking goal for Adjusted EBITDA for the relevant period and is based on the "Illustrative Total Segment Operating Margin Goal" less illustrative Core SGA assumed to be at $150mm for all periods 2024 onward including the pro rata share of Core SG&A from unconsolidated entities. For the purpose of this presentation, we have assumed an average Total Segment Operating Margin between $9.57 and $13.64 per MMBtu for all downstream terminal economics, because we assume that (i) we purchase delivered gas at a weighted average of $6.68 in 2023, (ii) our volumes increase over time, and (iii) we will have costs related to shipping, logistics and regasification similar to our current operations because the liquefaction facility and related infrastructure and supply chain to deliver LNG from Pennsylvania or Fast LNG (“FLNG”) does not exist, and those costs will be distributed over the larger volumes. For our Brazil assets we assume an average delivered cost of gas of $15.31 in 2023 based on industry averages in the region. Illustrative Adjusted EBITDA figures for the fiscal year ended 2023 assume that we generate at least $200 million on gain from Asset Sales in the fiscal year ended 2023. We cannot provide assurance that we will be able to achieve this result. We assume all Brazil terminals and power plants are Operational and earning revenue through fuel sales and capacity charges or other fixed fees. For Vessels chartered to third parties, this measure reflects the revenue from those charters, capacity and tolling arrangements, and other fixed fees, less the cost to operate and maintain each ship, in each case based on contracted amounts for ship charters, capacity and tolling fees, and industry standard costs for operation and maintenance. We assume an average Total Segment Operating Margin of up to $162k per day per vessel. For Fast LNG, this measure reflects the difference between the delivered cost of open LNG and the delivered cost of open market LNG less Fast LNG production cost. These costs do not include expenses and income that are required by GAAP to be recorded on our financial statements, including the return of or return on capital expenditures for the relevant project, and selling, general and administrative costs. Our current cost of natural gas per MMBtu is higher than the cost we would need to achieve Illustrative Total Segment Operating Margin Goal, and the primary drivers for reducing these costs are the reduced costs of purchasing gas and the increased sales volumes, which result in lower fixed costs being spread over a larger number of MMBtus sold. References to volumes, percentages of such volumes and the Illustrative Total Segment Operating Margin Goal related to such volumes (i) are not based on the Company’s historical operating results, which are limited, and (ii) do not purport to be an actual representation of our future economics. Actual circumstances could differ materially from the assumptions, and actual performance and results could differ materially from, and there can be no assurance that they will reflect, our corporate goal.
Endnotes 37 4. This statement reflects management’s estimate of anticipated volumes and sales prices to customers who have an investment grade credit rating. 5. This statement reflects management’s estimate of expected earnings growth, which growth is expected to be driven meaningfully by increased sales in Puerto Rico and Brazil. 6. The Company’s Terminals that are in Operation or Under Development. “Online”, “In Operation”, “Operational”, "Operating", "Completion", "Completed", “COD” or “commercial operation date”, “Deployment” or similar statuses (either capitalized or lower case) with respect to a particular project means we expect gas to be made available in the near future, gas has been made available to the relevant project, or that the relevant project is in full commercial operations. Where gas is going to be made available or has been made available but full commercial operations have not yet begun, full commercial operations will occur later than, and may occur substantially later than, our reported Operational, Completion or Deployment date, and we may not generate any revenue until full commercial operations have begun. We cannot assure you if or when such projects will reach full commercial operation. Our ability to export liquefied natural gas depends on our ability to obtain export and other permits from governmental and regulatory agencies. No assurance can be given that we will receive required permits, approvals and authorizations from governmental and regulatory agencies in connection with the exportation of liquefied natural gas on a timely basis or at all or that, once received, we will be able to maintain in full force and effect, renew or replace such permits, approvals and authorizations. “Under Development”, “Development,” “In Construction” or similar statuses means that we have taken steps and invested money to develop a facility, including execution of agreements for the development of the project (subject, in certain cases, to satisfaction of conditions precedent), procuring land rights and entitlements, negotiating or signing construction contracts, and undertaking active engineering, procurement and construction work. Our development projects are in various phases of progress, and there can be no assurance that we will continue progress on each development as we expect or that each development will be Completed or enter full commercial operations. There can be no assurance that we will be able to enter into the contracts required for the development of these facilities on commercially favorable terms or at all. If we are unable to enter into favorable contracts or to obtain the necessary regulatory and land use approvals on favorable terms, we may not be able to construct these assets as expected, or at all. Additionally, the construction of facilities is inherently subject to the risks of cost overruns and delays. 7. Reflects management estimates of MW that may eventually be produced from the Company’s power plants that are in operation or under development. 8. Refers to vessels that are owned by the Company or Energos Infrastructure, the joint venture in which we own 20%. 9. The Company’s Liquefiers that are in Operation or Under Development.
Endnotes 38 10. “Forward Customer Contracted Margin” or “FCCM” means the nominal contracted operating margin on a specific date of signed downstream contracts for the remaining term of the respective customer contracts. NFE calculates FCCM using the following methodology: (1) NFE first calculates monthly operating margin by downstream contract for the effective contractual period. The general approach for calculating monthly operating margin by downstream contract is: Contracted Revenue Pricing (-) NFE’s W.A. Portfolio LNG Supply Cost (-) NFE’s W.A. Terminal & Marine Opex Cost (x) Forecasted Downstream Volumes (within Contractual Limits) (=) Operating Margin (2) NFE then takes the monthly operating margin for each downstream contract and adds them on a prospective basis at given points in time. (e.g. Jan 1, 2022, Jan 1, 2023, etc.). This calculation produces a nominal FCCM for each downstream contract. The nominal FCCM for all downstream contracts are added together, and the product of this calculation is then presented as one aggregate number. “Illustrative Forward Customer Contracted Margin Goal” is an example of management’s aspirational goals of an amount of FCCM that NFE may achieve. It is important for readers to note several points regarding these calculations: First, FCCM is an estimated calculation based on management’s estimates of factors such as weighted average portfolio LNG supply costs, weighted average terminal and marine operating expense cost and management’s forecast of future downstream volumes. Each of these components are estimates and, as a result, the actual numbers for each component could differ materially from these estimates. Second, the calculation of a monthly operating margin is an estimated figure prepared by management based on its current expectations for the performance of downstream contracts. The actual timing for, and amounts of, prospective contractual revenues could differ materially from these estimates. Third, a number of the contracts included in the Illustrative Forward Customer Contract Margin Goals are connected to projects that have not yet been completed and as a result, no revenue has yet been received under those customer contracts. The targeted value of the Illustrative Forward Customer Contract Margin Goals also assumes that none of the contracts included will be terminated prior to the end of its stated term. As a result, FCCM and Illustrative Forward Customer Contract Margin Goals are estimates that have inherent limitations and should not be regarded as guarantees of future performance. Management estimates for each component of the calculations could differ materially from future actual results. Accordingly, readers should not rely on these targets and estimates – they are simply illustrations. 11. Management’s estimate based on operational experience and expectations of the capacity for a sample terminal. 12. Management’s estimate of potential capacity and utilization at the Company’s operating terminals and terminals under development. Actual capacity may be lower, especially for terminals that are not yet fully Operational (Barcarena, Santa Caterina and Nicaragua).
Endnotes 39 13. “Free Cash Flow” or “FCF” is not a measurement of financial performance under GAAP and should not be considered in isolation or as an alternative to income from operations, net income, cash flow from operating activities or any other measure of performance or liquidity derived in accordance with GAAP. We believe this non-GAAP measure, as we have defined it, offers a useful supplemental view of the overall operation of our business in evaluating the effectiveness of our ongoing operating performance in a manner that is consistent with metrics used for management’s evaluation of the Company’s overall performance. We believe Free Cash Flow is a useful performance measure for management, investors and other users of our financial information to evaluate our performance and to measure and estimate the ability of our assets to generate earnings after costs of interest, taxes and other costs to operate our business, which could be used for discretionary purposes such as continued development, common stock dividends or retirement of debt. Free Cash Flow is defined as Adjusted EBITDA less interest expense, tax expense and other adjustments that are removed in the calculation of Adjusted EBITDA, including but not limited to, transaction and integration costs, contract termination charges and loss on mitigations sales, asset impairment expense, interest expense (net), other expense (income), net loss on extinguishment of debt, changes in fair value of non-hedge derivative instruments and contingent consideration, and adjusting for certain items from our SG&A not otherwise indicative of ongoing operating performance, such as non-cash share-based compensation and severance expense, non-capitalizable development expenses, cost to pursue new business opportunities and expenses associated with changes to our corporate structure, and the impact of equity in earnings (losses) of certain unconsolidated entities and excludes noncontrolling interest and our pro rata share of Adjusted EBITDA from certain unconsolidated entities. Free Cash Flow is mathematically equivalent to net income attributable to stockholders plus depreciation and amortization each as reported in our financial statements. The principal limitation of Free Cash Flow is that it excludes significant expenses and income that are required by GAAP to be recorded in our financial statements. Investors are encouraged to review the related GAAP financial measures and the reconciliation of Free Cash Flow to our GAAP net income, and not to rely on any single financial measure to evaluate our business. Free Cash Flow does not have a standardized meaning, and different companies may use different Free Cash Flow definitions. Therefore, Free Cash Flow may not be necessarily comparable to similarly titled measures reported by other companies. Free Cash Flow should not be construed as alternatives to net income and diluted earnings per share attributable to New Fortress Energy, which are determined in accordance with GAAP. 14. “Illustrative FCF Goal” means the Illustrative Adjusted Net Income Goal plus non-cash depreciation and amortization expense added back at approximately $180 million in 2023, increasing to $250 million in 2024, and reaching a Run Rate cost of approximately $275 million per year by 2025. References to amounts and the Illustrative Adjusted Net Income Guidance (i) are not based on the Company’s historical operating results, which are limited, and (ii) do not purport to be an actual representation of our future economics. Actual circumstances could differ materially from the assumptions, and actual performance and results could differ materially from, and there can be no assurance that they will reflect, our corporate goal. 15. “Adjusted Net Income” means Net Income attributable to stockholders as presented in the relevant Form 10-K or Form 10-Q for the relevant financial period as adjusted by non-cash impairment charges or losses on disposal of our assets. 16. “Adjusted EPS” is not a measurement of financial performance under GAAP and should not be considered in isolation or as an alternative to any measure of performance or liquidity derived in accordance with GAAP. We calculate Adjusted EPS as Adjusted net income divided by the weighted average shares outstanding on a fully diluted basis for the period indicated. We believe this non-GAAP measure, as we have defined it, offer a useful supplemental view of the overall evaluation of the Company in a manner that is consistent with metrics used for management’s evaluation of the Company’s overall performance. Adjusted EPS does not have a standardized meaning, and different companies may use different definitions. Therefore, this term may not be necessarily comparable to similarly titled measures reported by other companies. 17. “Illustrative Adjusted EPS Goal” is not a measurement of financial performance under GAAP and should not be considered in isolation or as an alternative to any measure of performance or liquidity derived in accordance with GAAP. We calculate Illustrative Adjusted EPS Goal as adjusted net income divided by the weighted average shares outstanding on a fully diluted basis as of June 30, 2023. We believe this non-GAAP measure, as we have defined it, offers a useful supplemental view of the overall evaluation of the Company in a manner that is consistent with metrics used for management’s evaluation of the Company’s overall performance. Illustrative Adjusted EPS Goal does not have a standardized meaning, and different companies may use different definitions. Therefore, this term may not be necessarily comparable to similarly titled measures reported by other companies. 18. “Illustrative Adjusted Net Income Goal” reflects our illustrative Total Segment Operating Margin, excluding interest expenses from our debt facilities assuming a weighted average interest rate of 9% on $6.5 billion pro forma outstanding debt offset by capitalized income of approximately $250 million in 2023, $200 million in 2024, and less than $50 million in 2025, taxed at an effective tax rate of approximately 15%, corporate SGA expenses of approximately $200 million in 2023 and $150 million in 2024 and 2025, approximately $40 million per year illustrative income from equity investments in joint ventures from 2023 to 2025, interest on outstanding cash balances equal to approximately 8% on unrestricted cash accounts, and depreciation and amortization in the amount of $180 million in 2023, $250 million in 2024, and $275 million in 2025, including FLNG depreciated over a 20-year life starting on its expected date of start of operations. References to amounts and the Illustrative Adjusted Net Income Goal (i) is not based on the Company’s historical operating results, which are limited, and (ii) does not purport to be an actual representation of our future economics. Actual circumstances could differ materially from the assumptions, and actual performance and results could differ materially from, and there can be no assurance that they will reflect, our corporate goal. 19. Reserved. 20. Based on management’s expectations related to among other things, the closing of the planned financings on acceptable terms, the Company’s ability to (i) achieve the Illustrative Free Cash Flow Goals, (ii) potentially repurchase, redeem or otherwise acquire part of the Senior Secured 2025 Notes and (iii) complete targeted Asset Sales of approximately $1.0 billion in the next 12 months. Actual circumstances could differ materially from the assumptions, and actual performance and results could differ materially from, and there can be no assurance that they will reflect, our corporate goal.
Endnotes 40 21. Expected COD, lead times and expected development times used in this Presentation indicate our internal evaluations of a project’s expected timeline. They refer to us completing certain stages of projects within a timeframe and within a spectrum of budget parameters that, when taken as a whole, are substantially consistent with our business model. These timeframes include assumptions regarding items that are outside our control, including permitting, weather, supply of equipment and materials, and other potential sources of delay. To the extent that projects have not yet started or are currently under development, we can make no assurance that such projects are on track within the timeline parameters we establish. Additionally, the construction of facilities is inherently subject to the risks of cost overruns and delays. If we are unable to construct, commission, complete and operate any of our facilities as expected, or, when and if constructed, any of them do not accomplish our goals, estimates regarding timelines, budget and savings could be materially and adversely affected. 22. “First Gas” or “First LNG” refers to the date on which (or, for future dates, management's current estimate of the date on which) natural gas and/or LNG is expected for a project, including a facility in development. Full commercial operation of such project will occur later than, and may occur substantially later than, the date of first gas or first LNG. We cannot assure you if or when such projects will reach the date of delivery of first gas or LNG, or full commercial operations. 23. Any determination regarding our dividend policy is determined by our board of directors. We cannot predict what, if any, changes the board of directors may determine regarding our dividend policy. 24. Management’s estimate of the fully funded capital plan includes the funding of all capital expenditures related to the installation and operation of the Company’s FLNG 1 and 2 projects and the payment of any current outstanding amounts related to the Company’s FLNG 3, 4 and 5 projects.