#1August 2023 Q2 2023 Investor Presentation NewFortress energy OOOOOD#21. Executive Summary 2. Construction Update 3. Capacity & Customers 4. Customers & Terminals Update 5. Financial Results 6. Appendix 2#3Achieved strong earnings for 1H 2023 Executive Summary Quarterly financial results & Guidance (1) Adj. EBITDA (2) 1H 2022 Q1 2022 Q2 2022 Total Segment Revenue Adj. EBITDA Net Income $258mm $283mm $541mm Guidance (1) of ~$1.6bn in 2023(6) & ~$2.4bn 2024(6) 2021 2022 Adj. EBITDA (2) 1H 2023 Q1 2023 Q2 2023 Total $93(4) $1,696(3) $2,613(3) ~$3,100(5) $185(4) Guidance (1) 2023E $605(2) $1,071(2) ~$1,600(6) $440mm $246mm $686mm ~$800(7) 2024E ~$4.8bn(5) ~$2.4bn(6) ~$1.5bn(7) 1H23 Adj. EBITDA(²) is $145mm higher than 1H22 Q2 2023 earnings down from Q1 primarily due to lower cargo sales $3.2bn of infrastructure (8) converting from construction to revenue in 2H23 Guidance (1) of $1.6bn for FY2023(6) & $2.4bn for FY2024(6) Reducing FY2023 Guidance(1) primarily due to construction completion schedule(11) 3#4Executive Summary Capital (8) invested to date translates to strong earnings Adj. EBITDA(2)(6) expected to significantly increase as projects enter service(10) & capex(8) declines ~$7bn invested(8) in core projects over the past 5+ years Adj. EBITDA (2) accelerates from $33mm in 2020(²) to $2.4bn in 2024(6) ...while Capex(8) declines from $1.7bn in 2023(8) to $250mm in 2024(⁹) $mm Adj. EBITDA(2)(6) growth and capex(8) decline expected. as $3.2bn(8) of projects enter service(10) in 2H 2023(11) $605 $33 2020 2021 $1,071 سانت 2022 $1,600 2023 (2) (6) (6) AEBITDA $2,4006) 2024 $240 $2,410 2020 2021 $1,460 (9) $1,660 $250 2022 2023 2024 ■Capex (8) Plan to finance construction on balance sheet, then refinance at the asset level once complete(10) (9) 4#5Significant number of projects expected to come online (10) in next few months(11) Project FLNG 1 Puerto Rico power Barcarena Executive Summary We are at an inflection point as $3.2bn of infrastructure(8) comes online (10) in the next ~90 days(11) Santa Catarina La Paz Description 1.4 MTPA liquefier 150 MW Palo Seco; 200 MW San Juan 3 MTPA LNG terminal 3 MTPA LNG terminal 135 MW power plant Investment (8) $1.3bn $500mm $700mm $500mm $200mm Expected (11) COD(10) Sep. 2023 May 2023; September 2023 Dec. 2023 Jan. 2024 Aug. 2023 $3.2bn of infrastructure(8) being converted from construction to revenue producing Significant positive impact on the company LO 5#6Executive Summary Increasing infrastructure capacity drives growth in volumes & earnings Our investments(8) in LNG & power infrastructure create massive downstream opportunities... # of Terminals LNG Capacity LNG Volumes Adj. EBITDA (2) # TBtu TBtu 2016 1 20 $mm ($25) 2017 1 20 8 ($22) ...which in turn creates capacity at our terminals around the world... 2018 2 20 8 ($55) 2019 2 170 17 ($115) 2020 3 235 18 $33 2021 5 470 74 $605 ...and leads to significant growth in volumes & Adj. EBITDA (2) 2022 5 470 2023(¹) 88 5 620(13) 136(14) 2024(1) 7 920(13) 185(14) $1,071 $1,600 (6) $2,400 (6) 6#71. Executive Summary 2. Construction Update 3. Capacity & Customers 4. Customers & Terminals Update 5. Financial Results 6. Appendix 7#8Construction Update FLNG 1 is mechanically complete(15), being installed & expect COD(10) in 60 days(11) FLNG 1 consists of 3 platforms ZN N Platform I Function: Gas treatment Ready September 1st(11) How it works liquefier platforms T Platform II Function: Liquefaction Ready September 10th (11) cryogenic flexible hose system IN AS frood storage vessel ship to ship transfer NEPONERE Platform III UNNAR Function: Power & people Onsite in Altamira LNGC 17 8#9$/MMBtu Construction Update Fast LNG's rapid development & deployment(10) generates significant value $18.00 $16.00 $14.00 $12.00 $10.00 $8.00 $6.00 $4.00 Deploying (10) FLNG now creates significant value vs. the market (~$1.5bn (16) over 3 years) Forward TTF Curve Avg. FLNG cost Jan-24 Jun-24 ~$1.5bn (16) over 210 TBtus over 3 years Nov-24 Apr-25 Sep-25 Feb-26 Jul-26 Dec-26 $$ FLNG produces LNG at significant cost savings to market over the next 3 years Operational flexibility to manage supply & demand imbalances at our terminals 9#101. Executive Summary 2. Construction Update 3. Capacity & Customers 4. Customers & Terminals Update 5. Financial Results 6. Appendix 10#11● ● mas Capacity & Customers Calculating the capacity of NFE's LNG terminals ANTHONY VEDER Montego Bay, Jamaica First gas(17): Q4 2016 Capacity: 8,000m³ of onshore storage LNG vessel berth & onshore storage Serves Jamaica Public Service on long-term gas supply contract for the Bogue power plant Supplies LNG through trucks to over 20 industrial & hospitality customers across Jamaica Calculating the annual capacity of NFE's MoBay terminal Storage Capacity (x) Weekly Reloads (=) Weekly Capacity (x) Weeks (=) Total Capacity m³ Reloads/week m³ Weeks/yr m³ TBtu 8,000 2 16,000 52 832,000 ~20 11#12Rule of thumb: ~50 TBtu = 1 tonne Mobay Old Harbour Puerto Rico (Current) Mexico Puerto Rico (Increased Capacity) Barcarena Santa Catarina Nicaragua Capacity & Customers Terminal capacity increasing >100% by YE 2024(13) ~18 MTPA of LNG terminal capacity by YE 2024(13) Total TBtu 20 150 65 150 85 150 150 150 920 Capacity MTPA 0 3 1 3 2 3 3 3 18 2020 9.53% 2021 15.74% Utilization 2022 26.17% 2023(13) 26.45% 2024(13) 21.74% 12#13Capacity & Customers Continued growth in utilization & capacity drive earnings growth & quality Two pathways to accelerate growth: 1. increasing utilization & 2. entering new markets Increased utilization & organic growth i Current terminal utilization modest Highly accretive margins Incremental volumes with no increase in capex or operating costs X Embedded position in growth markets Continued adoption. of cheaper, cleaner energy in NFE's existing high-growth locations. Additional terminal infrastructure Continue to develop LNG terminals to meet energy demand in under-served, high-growth markets Attractive return on capital Target ROIC >20% ● Opportunities in Caribbean, Central America, South Africa & Vietnam Portfolio value of growing terminal capacity More opportunities for organic growth Increasing scale & diversity of cash flows ● ● 13#141. Executive Summary 2. Construction Update 3. Capacity & Customers 4. Customers & Terminals Update 5. Financial Results 6. Appendix 14#15Customers & Terminals Update We have been investing in Puerto Rico since 2017 Our goal has always been to partner with Puerto Rico to deliver critical energy infrastructure solutions 2017 New Fortress Energy first came to Puerto Rico after Hurricane Maria devastated the island & began developing our LNG terminal 2020 Signed 300 MW gas supply deal with PREPA & began operations at our terminal JS INEOS INDEPENDENCE melal in Pr INEC BMW D PRIVAL 15#16Victoria Añasco San Sebastian Mayaguez Wanta Acacias ET 17 power sites (i) (ii) In 2021, PREPA issued an RFP to take over operations of its assets(i) Customers & Terminals Update In 2021, PREPA, Puerto Rico's utility, began privatization San German Hatil Caonillas Guanica Barceloneta Dos Bocos Canas Ponce 4,693 MW nameplate capacity Vega Bajaborado Toro Negro Barranquias ************ Comerio Juana az Pattern ind Farm Santa Isabe Martin Cena Monacillos Viaducto Isla Grande G.I.S. Hato Rey Cayey Jobos iii¡ 700 employees Berwineanovanas Palmer Caguas Rio Blanco Juncos Daguao Humaca Shell Fajardo Maunabo se 1.5mm customers We won the RFP & GeneraPR, our subsidiary, took over from PREPA on July 1(1⁹) These assets encompass 85% of Puerto Rico's generation capacity... but they are currently old, inefficient & unreliable 1981 average year built(i) Improve reliability of the power grid 630x more likely to be without power than mainland U.S. (ii) * GeneraPR mandate has two main goals: Jeg Public-Private Partnerships Authority, "Partnership Committee Report: Puerto Rico Public-Private Partnership for the Puerto Rico Electric Power Thermal Generation Facilities", October 17, 2022 LUMA Resource Accuracy Report Lower power costs 16#17Customers & Terminals Update U.S. government is very focused on creating a clean, resilient power grid in Puerto Rico Cooperation between DOE, FEMA & Army Corps (i) Have allocated $30bn federal funds(i) for the Recovery of Puerto Rico FEMA Press Release NR 561, "FEMA Reaches Historic $30 Billion Milestone for the Recovery of Puerto Rico", April 16, 2023 Focus of funds in 3 primary areas 1 Grid resilience 2 3 Wind, solar & batteries Short & long-term gas & power 17#18Customers & Terminals Update In late 2022, in the wake of Hurricane Fiona, FEMA called for 350 MW(20) of emergency power to help stabilize the grid FEMA stepped in & issued an RFP for two emergency power installations(20) 1 2 Palo Seco: 150 MW San Juan: 200 MW We won the RFP to supply all of the turbines and gas for 350 MW(20) 200 MW San Juan project 18#19Customers & Terminals Update There are several ways NFE can help the U.S. government reach their goals 1. Help provide the island with short-term power(20) (i) 150 MW in Palo Seco 5 miles from San Juan terminal, turned on (10) in June 200 MW in San Juan adjacent to San Juan terminal, turning on (10) in September (11) 2. Help supply any conversions of existing oil/diesel power plants(i) 57% diesel/HFO (2675 MW) 200 43% gas 3. Participate in any long-term power solution 75% of island's population in San Juan, where NFE terminal is located 3700 MW dispatchable power needed long-term, batteries or gas We are excited to be part of building this blueprint for a zero-carbon grid Public-Private Partnerships Authority, "Partnership Committee Report: Puerto Rico Public-Private Partnership for the Puerto Rico Electric Power Thermal Generation Facilities", October 17, 2022 19#201. Executive Summary 2. Construction Update 3. Capacity & Customers 4. Customers & Terminals Update 5. Financial Results 6. Appendix 20#21Total Seg. Revenue ($mm) Total Seg. Op. Margin(21¹) ($mm) (-) Core SG&A(2) ($mm) Financial Results Realized $246mm of Adj. EBITDA(2) for Q2-23 Adj. EBITDA(2) ($mm) Adj. Net (Loss) Income(22) ($mm) (excluding non-cash impairment charges) Adj. EPS(23) ($/share), Diluted (excluding non-cash impairment charges) Net (Loss) Income(4) ($mm) EPS ($/share), Diluted (i) After NCI Q1 2023 $601 $481 ($41) $440 $187 $0.90 $152 $0.71 Q2 2023 $561 $294 ($47) $246 $120 $0.58 $120 $0.58 QoQ A ($40) ($187) ($6) ($194) ($68) ($0.32) ($32) ($0.13) NFE completed 2 financings in the past 60 days, thus strengthening our balance sheet 1. $200mm equipment financing secured by the turbines purchased for Puerto Rico 2. $400mm term loan that will be replaced with upsized facility secured by FLNG 1 21#221. Executive Summary 2. Construction Update 3. Capacity & Customers 4. Customers & Terminals Update 5. Financial Results 6. Appendix 22#23Appendix - Construction Update Several additional construction projects in progress(24) Project Ireland Barcarena power FLNG 2 & 3 201 JF HULLE Description 400 MW power plant 605 MW power plant 1.4 MTPA liquefier Expected(11) COD(10) October 2026 July 2025 March 2025 23#24Appendix - Hydrogen Update ZeroParks: A pure-play, green hydrogen infrastructure company We've laid out a simple and effective business model to develop a leading green hydrogen business in the U.S. Our business model 1. Identify & secure best sites in the U.S. Near large and diverse end-users Access to long-term, affordable renewable power Compelling logistics: pipelines, railroads, deep water ports 2. Act on major decarbonization opportunity Focus on hard-to-abate sectors of the economy that cannot be directly electrified These comprise majority of point-source emitters in the United States (i) (i) U.S. Environmental Protection Agency (EPA), Greenhouse Gas Reporting Program (GHGRP) 3. Develop portfolio of hydrogen parks Become the largest and most valuable clean hydrogen business in the United States 24#25In Q2 Appendix - Hydrogen Update Beaumont (ZeroPark 1) operational updates are gaining momentum Advancing one of the largest green hydrogen projects in North America H H Technology signed agreement for first 100 MW PEM electrolysis technology Funding $100mm, asset level debt financing secured at attractive terms 120 Project execution FEED complete, currently selecting construction sub-contractors with Black & Veatch Agile development purchased all long lead items (transformers, critical power equipment) Team 3 new ZeroParks team members in NYC & Houston; 60+ cumulative years hydrogen experience $ 1.89 2H23 & beyond ~$55mm of run-rate, annualized EBITDA(6) by 2025(11) Beaumont capable of expanding to 200 MW of green hydrogen production First production in Fall of 2024(10) with COD(10) in early-2025(11) Beaumont is the blueprint for projects 2-5, currently in development(24) 25#26Major items to be defined by U.S. Treasury... 11 Appendix - Hydrogen Update Update: Inflation Reduction Act of 2022(25) US Treasury is due to publish its full guidance for 45V tax credit eligibility O Additionality Deliverability Time matching Our expectations Treasury ruling expected next week, however the full guidance could slip into the Fall Ruling likely to include a phased approached but one that gets the industry going all while working toward IPCC's climate goals ZeroParks business positioned for profitability in all IRA(25) ruling scenarios We're very optimistic that we can get this right and strike the right balance... to create the cost reductions that we need for electrolyzers, but do it in a way that puts us on a path to having the highest standards for green hydrogen going forward during the course of this decade." - John Podesta (Senior Advisor to the President for Clean Energy Innovation and Implementation, August 7, 2023, Bloomberg News) 26#27ZeroParks spin considerations Started ~3.5 years ago; working towards tax-free spin to occur in the near future(11) Appendix - Hydrogen Update What ZeroParks means for NFE shareholders The first independent hydrogen producer Establishing ZeroParks as a separate, publicly traded, company continues to be our main objective (i) Deloitte's 2023 global green hydrogen outlook Market 'Megatrend' call option When our current pipeline of 5 projects is up & running(10) on the green hydrogen economy in the U.S. & abroad Production ~98k TPA of green hydrogen production $1.4 trillion(i) market opportunity by 2050 Economics ~$250mm of run-rate, annualized EBITDA(6) by YE'2026(11) Development Strategic access strategically geolocated near end users in hard-to-abate sectors of the economy Continuing to source additional opportunities throughout USA that leverage NFE's experience in infrastructure & project development 27#28(in thousands of U.S. dollars) Net income Add: Interest expense Add: Tax provision (benefit) Add: Contract termination charges and loss on mitigation sales Add: Depreciation and amortization Add: Asset impairment expense Add: SG&A items excluded from Core SG&A Add: Transaction and integration costs Add: Other (income) expense, net Appendix Adjusted EBITDA (non-GAAP) Adjusted EBITDA Add: Changes in fair value of non-hedge derivative instruments and contingent consideration Add: Loss on extinguishment of debt, net Add: Pro rata share of Adjusted EBITDA from unconsolidated entities Less: Loss (income) from equity method investments Add: Contract acquisition cost Q1 2022 $241,181 44,916 (49,681) 34,290 7,081 1,901 (19,725) (2,492) 50,497 (50,235) $257,733 Q2 2022 $(178,431) 47,840 (86,539) 36,356 48,109 8,270 4,866 (22,102) 2,247 49,951 372,927 $283,494 Q1 2023 $151,566 71,673 28,960 34,375 11,071 494 25,005 111,140 15,432 (9,980) $439,736 Q2 2023 $120,100 64,396 15,322 42,115 8,422 1,554 (6,584) (2,835) (2,269) 6,232 $246,453 28#29(in thousands of U.S. dollars) Net income Add: Interest expense Add: Tax provision (benefit) Add: Contract termination charges and loss on mitigation sales Add: Depreciation and amortization Add: Asset impairment expense Add: SG&A items excluded from Core SG&A Add: Transaction and integration costs Add: Other (income) expense, net Add: Changes in fair value of non-hedge derivative instruments and contingent consideration Add: Loss on extinguishment of debt, net Add: Pro rata share of Adjusted EBITDA from unconsolidated entities Less: Loss (income) from equity method investments Add: Contract acquisition cost Adjusted EBITDA (non-GAAP) Adjusted EBITDA FY 2016 $(32,926) 5,105 (361) 2,341 I (53) 1,177 Appendix $(24,717) FY 2017 $(31,671) 6,456 526 2,761 1 I I (301) T $(22,229) FY 2018 $(78,076) 11,248 (338) 3,321 T I T (784) 9,568 $(55,061) FY 2019 $(204,319) 19,412 439 5,280 7,940 58,789 (2,807) $(115,266) FY 2020 $(263,965) 65,723 4,817 124,114 32,376 28,162 4,028 5,005 33,062 $33,322 FY 2021 $92,711 154,324 12,461 98,377 62,737 44,671 (17,150) 2,788 10,975 157,109 (14,443) $604,560 FY 2022 $184,786 236,861 (123,439) 142,640 50,659 61,640 21,796 (48,044) (103,490) 14,997 160,684 472,219 $1,071,309 29#30(in thousands of U.S. dollars) Total Segment Operating Margin Less: Core SG&A Less: Pro rata share of Core SG&A from unconsolidated entities Adjusted EBITDA (non-GAAP) Adjusted EBITDA FY 2020 $125,302 91,980 Appendix $33,322 FY 2021 $746,430 137,144 4,726 $604,560 FY 2022 $1,250,293 174,410 4,574 $1,071,309 Q1 2022 $300,083 40,960 1,390 $257,733 Q2 2022 $327,448 42,040 1,914 $283,494 Q1 2023 $480,817 41,067 14 $439,736 Q2 2023 $293,834 47,381 $246,453 30#31(in thousands of U.S. dollars) Total Selling, general and administrative Core SG&A SG&A items excluded from Core SG&A Adjusted EBITDA FY 2020 $120,142 91,980 Appendix 28,162 FY 2021 $199,881 137,144 62,737 FY 2022 $236,050 174,410 61,640 Q1 2022 $48,041 40,960 7,081 Q2 2022 $50,310 42,040 8,270 Q1 2023 $52,138 41,067 11,071 Q2 2023 $55,803 47,381 8,422 31#32(in thousands of $) Appendix Segment operating margin reconciliation Three Months Ended June 30, 2023 Total revenues Cost of sales (1) Vessel operating expenses Operations and maintenance Consolidated Segment Operating Margin Less: Selling, general and administrative Transaction and integration costs Depreciation and amortization Interest expense Other (income) expense, net (Income) from equity method investments Tax provision Net income Terminals and Infrastructure 495,504 222,371 33,697 239,43 Ships 65,841 11,443 54,398 Total Segment 561,345 222,371 11,443 33,697 293,83 Consolidation and Other (2) 3,397 (3,397) Consolidated 561,345 225,768 11,443 33,697 290,437 55,803 1,554 42,115 64,396 (6,584) (2,269) 15,322 120,100 (1) Cost of sales in the Company's segment measure only includes gains and losses on derivative transactions that are an economic hedge of our commodity purchases and sales, and in the second quarter of 2023, realized gains of $146,112 were recognized as a reduction to Cost of Sales. Unrealized changes in the mark-to-market of derivative transactions of $(2,835) reconcile Cost of sales in the segment measure to Cost of sales in our condensed consolidated statement of operations and comprehensive income (loss). The Company has excluded contract acquisition costs that do not meet the criteria for capitalization from the segment measure. Contract acquisition costs of $6,232 for the three and six months ended June 30, 2023 reconcile Cost of sales in the segment measure to Cost of sales in the condensed consolidated statements of operations and comprehensive income (loss). (2) Consolidation and Other adjusts for the exclusion of unrealized mark-to-market gain or loss on derivative instruments. 32#33(in thousands of $) Appendix Segment operating margin reconciliation Three Months Ended March 31, 2023 Total revenues Cost of sales (1) Vessel operating expenses Operations and maintenance Consolidated Segment Operating Margin Less: Selling, general and administrative Transaction and integration costs Depreciation and amortization Interest expense Other (income) expense, net (Income) from equity method investments Tax provision Net income Terminals and Infrastructure 502,608 73,798 26,671 402,139 Ships 97,917 19,239 78,678 Total Segment 600,525 73,798 19,239 26,671 480,817 Consolidation and Other (2) (21,394) 111,140 (5,948) (126,586) Consolidated 579,131 184,938 13,291 26,671 354,231 52,138 494 34,375 71,673 25,005 (9,980) 28,960 151,566 (1) Cost of sales in the Company's segment measure only includes gains and losses on derivative transactions that are an economic hedge of our commodity purchases and sales, and in the first quarter of 2023, realized gains of $146,112 were recognized as a reduction to Cost of Sales. Unrealized changes in the mark-to-market of derivative transactions of $111,140 reconcile Cost of sales in the segment measure to Cost of sales in our condensed consolidated statement of operations and comprehensive income. (2) Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to 50% ownership of the common units of Hilli LLC in our segment measure and exclusion of the unrealized mark-to-market gain or loss on derivative instruments. 33#34(in thousands of $) Appendix Segment operating margin reconciliation Three Months Ended June 30, 2022 Total revenues Cost of sales Vessel operating expenses Operations and maintenance Consolidated Segment Operating Margin Less: Selling, general and administrative Transaction and integration costs Depreciation and amortization Asset impairment expense Interest expense Other (income), net Loss from equity method investments Tax (benefit) Net income Terminals and Infrastructure (1) 543,455 271,948 4,255 29,540 237,712 Ships (2) 111,024 21,288 89,736 Total Segment 654,479 271,948 25,543 29,540 327,448 Consolidation and Other (3) (69,624) 453 (6,915) (9,050) (54,112) Consolidated 584,855 272,401 18,628 20,490 273,336 50,310 4,866 36,356 48,109 47,840 (22,102) 372,927 (86,539) (178,431) (1) Terminals and Infrastructure includes the Company's effective share of revenues, expenses and operating margin attributable to 50% ownership of CELSEPAR. The loss attributable to the investment of $389,996 for the three months ended June 30, 2022 are reported in (Loss) income from equity method investments on the consolidated statements of operations and comprehensive income (loss). (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 $17,069 for the three months ended June 30, 2022 are reported in (Loss) 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. 34#35(in thousands of $) Appendix Segment operating margin reconciliation Year Ended December 31, 2022 Ships (2) Total revenues Cost of sales Vessel operating expenses Operations and maintenance Consolidated Segment Operating Margin Less: Selling, general and administrative Transaction and integration costs Depreciation and amortization Asset impairment expense Interest expense Other (income), net Loss from extinguishment of debt, net Loss from equity method investments Tax (benefit) Net income Terminals and Infrastructure (1) 2,168,565 1,142,374 129,970 896,221 444,616 90,544 354,072 Total Segment 2,613,181 1,142,374 90,544 129,970 1,250,293 Consolidation and Other (3) (244,909) (131,946) (27,026) (24,170) (61,767) Consolidated 2,368,272 1,010,428 63,518 105,800 1,188,526 236,051 21,796 142,640 50,659 236,861 (48,044) 14,997 472,219 (123,439) 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. 35#36(in thousands of $) Total revenues Cost of sales Vessel operating expenses Operations and maintenance Consolidated Segment Operating Margin Less: Selling, general and administrative Transaction and integration costs Depreciation and amortization Appendix Segment operating margin reconciliation Year Ended December 31, 2021 Interest expense Other (income), net Loss from extinguishment of debt (Income) from equity method investments Tax provision Net income Terminals and Infrastructure (1) 1,366,142 789,069 3,442 92,424 481,207 Ships (2) 329,608 64,385 265,223 Total Segment 1,695,750 789,069 67,827 92,424 746,430 Consolidation and Other (3) (372,940) (173,059) (16,150) (19,108) (164,623) Consolidated 1,322,810 616,010 51,677 73,316 581,80 199,881 44,671 98,377 154,324 (17,150) 10,975 (14,443) 12,461 92,711 (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 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. 36#37Appendix Adjusted Net Income and EPS (in thousands of U.S. dollars except for share amounts) Net income (loss) attributable to stockholders (GAAP) Non-cash impairment charges, net of tax Loss on disposal of investment in Hilli LLC Adjusted net income (Non-GAAP) Weighted-average shares outstanding - diluted Adjusted earnings per share - diluted Q1 2023 150,206 37,401 187,607 209,325,619 0.90 Q2 2023 119,248 119,248 205,711,467 0.58 37#38Disclaimers 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; the successful development, construction, completion, operation and/or deployment of facilities, including our FLNG and Puerto Rico projects, on time, within budget and within the expected specifications, capacity and design; ability to maintain our expected development timelines; our ability to increase earnings and free cash flows and decrease capital expenditures as various projects come online; our ability to refinance our projects at the asset level once complete; expectations regarding revenue generation of our facilities; potential downstream opportunities generated by our projects and related benefits to our strategy; expected growth of our terminal capacity, volumes of LNG and utilization rates; expected cost savings to be generated by our FLNG projects; ability to develop terminals and meet demand in markets; expectations regarding return on capital; expectations related to our business strategy, including ability for organic growth and increasing scale and diversity of cash flows; successful management of PREPA's power generation system and benefits to be derived; capitalization and funding of our projects, including financing of our projects; ability to develop a leading green hydrogen business and become the larges and most valuable clean hydrogen business; impact and benefits of IRA on our business; future strategic plans; and all the information in the Appendices. 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; cyclical or other changes in the LNG and natural gas industries; competition in the energy industry; failure to convert our customer pipeline into actual sales; risks related to the development, construction, commissioning and completion of facilities, including cost overruns and delays; 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; 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; 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. 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 t 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 base I on specified assumptions that are aspirational in nature ther 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. 38#391. 2. 3. 4. 5. 6. Endnotes "Guidance" means our forward-looking view for the relevant metric. The guidance is based on certain management assumptions applicable to the relevant metric. The guidance is not based on the Company's historical operating results, which are limited, and is provided for illustrative purposes only and therefore 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 guidance. "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. 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 of interest income), 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. "Segment Revenue" means Total Segment Revenue as presented in the relevant Form 10-K or Form 10-Q for the relevant financial period. "Net Income" means Net Income as presented in the relevant Form 10-K or Form 10-Q for the relevant financial period. "Illustrative Adjusted Segment Revenue Guidance" means our forward-looking goal for Segment Revenue for the relevant period adjusted to reflect the Company's anticipated volumes of LNG to be sold under binding contracts multiplied by the average price per unit at which the Company expects to price LNG deliveries, including fuel sales and capacity charges or other fixed fees, less the cost per unit at which the Company expects to purchase or produce and deliver such LNG or natural gas, including the cost to (i) purchase natural gas, liquefy it, and transport it to one of our terminals or purchase LNG in strip cargos or on the spot market, (ii) transfer the LNG into an appropriate ship and transport it to our terminals or facilities, (iii) deliver the LNG, regasify it to natural gas and deliver it to our customers or our power plants and (iv) maintain and operate our terminals, facilities and power plants. For vessels chartered to third parties, this measure reflects the revenue from ships chartered to third parties, capacity and tolling arrangements, and other fixed fees. 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 guidance. "Illustrative Adjusted EBITDA Guidance" means our forward-looking goal for Adjusted EBITDA for the relevant period and is based on the "Illustrative Total Segment Operating Margin Guidance" less illustrative Core SGA assumed to be at $130mm 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 Hygo + Suape assets we assume an average delivered cost of gas of $15.31 in 2023 based on industry averages in the region. 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 Guidance, 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 Guidance 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 guidance. 39#407. 8. 9. 10. 11. 12. Endnotes "Illustrative Adjusted Net Income Guidance" reflects our Illustrative Total Segment Operating Margin, excluding interest expenses from our debt facilities assuming a weighted average interest rate of 9.39% on $6.2bn pro forma outstanding debt offset by capitalized income of approximately $199mm in 2023, taxed at an effective tax rate of approximately 13.1%, corporate SGA expenses of approximately $155mm per year, approximately $40mm illustrative income from equity investments in joint ventures, interest on outstanding cash balances equal to approximately 3.5% on unrestricted cash accounts, and depreciation and amortization in an aggregate amount of $253mm on our operating assets, including FLNG depreciated over a 20-year life starting on its expected date of start of operations. References to amounts, rates and the Illustrative Total Segment Operating Margin related to such amounts (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 guidance. Capex, capital expenditure, capital investment or similar metrics 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 this measure is a useful performance measure for management, investors and other users of our financial information to evaluate the investment of capital or assets in our projects. We calculate our capital expenditures based on the book value of our property, plant and equipment, plus the value of construction in progress based on management's estimates, plus goodwill for the relevant project, before deducting any accumulated depreciation as presented in the relevant Form 10-K or Form 10-Q for the relevant financial period. For our Barcarena Power Plant and Terminal and Santa Catarina Terminal, capital expenditure represents amounts attributable to the purchase of those assets as part of our acquisition of Hygo completed in 2021. For our FLNG 1 project, capital expenditure represents management's estimates of costs directly applicable to our FLNG 1 project. Investors are encouraged to review the related GAAP financial measures, and not to rely on any single financial measure to evaluate our business. "Illustrative Capex Guidance" means management's expectations regarding the funding of the committed expenditures reflected and the estimated expenditures for the development of our projects. The estimated expenditures, including those related to project costs, are based on specified assumptions that may not be based on a measure of performance under GAAP and should not be relied upon for any reason. References to amounts and the Illustrative Capex 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 guidance. "Online", "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. 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. "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 of interest income), 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 mpensation 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. 40#4113. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. Endnotes Based on management's expectations on completion and start of commercial operations of the Company's terminals consistent with designed storage capacity and the number of loadings per year for any one terminal. Actual results could differ materially from the illustration and there can be no assurance we will achieve our goal. Based on Contracted volumes of LNG as of August 7, 2023 and management's volume estimates based on current perceived demand. Contracted or Committed means our volumes sold or expected to be sold to customers under binding contracts and awards under requests for proposals as of the period specified in the Presentation. There can be no assurance that we will enter into binding agreements for the awards we have under requests for proposals on a particular timeline or at all, or the terms of any such agreements. Some, but not all, of our contracts contain minimum volume commitments and are subject to certain conditions, including extensions and renewals, and our expected volumes to be sold to customers reflected in our Committed volumes are substantially in excess of such minimum volume commitments and assuming renewals of the terms thereof. Our near-term ability to sell these volumes is dependent on our customers' continued willingness and ability to continue purchasing these volumes in accordance with our expected timelines and to perform their obligations under their respective contracts. If any of our customers fails to continue to make such purchases or fails to perform their obligations under their respective contract, our operating results, cash flow and liquidity could be materially and adversely affected. References to Committed volumes in the future and percentages of these volumes in the future should not be viewed as guidance or management's view of the Company's projected earnings, is not based on the Company's historical operating results, which are limited, and does not purport to be an actual representation of our future economics. "Mechanical Completion" or similar statuses with respect to a particular project means we have completed construction and certain subsystems are ready to be handed over to the commissioning team. There may be several mechanical completion milestones defined for the various subsystems of a project. Therefore, no assurance can be given that we will be able to complete a project and begin operations even if a project has reached mechanical completion. Management's current estimates of the margin between TTF and FLNG production costs assumed for our FLNG 1 facility for LNG volume produced over a three-year period. 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 estimates. Refers to the date on which (or, for future dates, management's current estimate of the date on which) natural gas is first made available 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. We cannot assure you if or when such projects will reach the date of delivery of first gas, or full commercial operations. Reserved Refers to the selection of Genera PR LLC ("Genera"), an independently managed subsidiary of NFE, by the Puerto Rico Public-Private Partnerships Authority ("P3A"), in accordance with the requirement established by Act 120-2018 (Puerto Rico Electric System Transformation Act), for a ten-year operation and maintenance agreement with the Pue Rico Electric Power Authority ("PREPA") for the operation, maintenance, decommissioning and modernization of PREPA-owned thermal power generation system of approximately 4,693 MW after a mobilization period, as approved by the government of Puerto Rico, the Fiscal Oversight Management Board and Puerto Rico's Electricity Bureau. Refers to the support of Puerto Rico's grid stabilization project with additional power capacity to enable maintenance and repair work on the island's power system and grid with the installation and operation of 150MW of additional power to be generated at the Palo Seco Power Plant in Puerto Rico as well as the supply of natural gas, and an additional 200MW of power to be generated at the San Juan Power Plant in Puerto Rico as well as the supply of natural gas. "Total Segment Operating Margin" is the total of our Terminals and Infrastructure Segment Operating Margin and Ships Segment Operating Margin. "Terminals and Infrastructure Segment Operating Margin" included our effective share of revenue, expenses and operating margin attributable to our 50% ownership of Centrais Elétricas de Sergipe Participações S.A. ("CELSEPAR") prior to the Sergipe Sale. "Ships Segment Operating Margin" included our effective share of revenue, expenses and operating margin attributable to our ownership of 50% of the common units of Hilli LLC prior to the completion of the Hilli Exchange. Hilli LLC owns Golar Hilli Corporation ("Hilli Corp"), the disponent owner of the Hilli. "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. "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, 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. 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. 41#4224. 25. Endnotes "Under Construction", "Development," "In Development" 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. The Inflation Reduction Act was signed into law on August 16, 2022 (Public Law 117-169). The U.S. Department of the Treasury and the Internal Revenue Service (IRS) are charged with promulgating the climate and clean energy tax incentives included in the legislation. These implementing regulations have not yet been issued. Furthermore, the IRA is subject to decision, administration and implementation by various governmental agencies and bodies. There is no guarantee that such new implementing regulations or their interpretation, administration or implementation will be favorable to us or our business. In addition, new regulation can be subject to legal challenges in courts, which could lead to its suspension and prevent their implementation. 42