What changed in this filing

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Item 2. Management’s Discussion and Analysis

2024-08-09 compared with 2024-05-09 · 259 added, 172 removed, 377 unchanged (53% of the section changed)

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Unless otherwise indicated, dollar amounts are presented in millions.

Unless the context otherwise requires, references to “Company,” “NFE,” “we,” “our,” “us” or like terms refer to New Fortress Energy Inc.

Unless the context indicates otherwise, references to “Company,” “NFE,” “we,” “our,” “us” or like terms refer to New Fortress Energy Inc.

and its subsidiaries.

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We currently source LNG from long-term supply agreements with third-party suppliers and from our own liquefaction facility in Miami, Florida.

Upon the completion of commissioning in 2024, we expect to begin to source a portion of our LNG from our modular floating liquefaction facilities, which we refer to as "Fast LNG" or "FLNG." The Terminals and Infrastructure segment includes all terminal operations in Jamaica, Puerto Rico, Mexico and Brazil, as well as vessels utilized in our terminal or logistics operations.

We centrally manage our LNG supply and the deployment of our vessels utilized in our terminal or logistics operations.

We centrally manage our LNG supply and the deployment of our vessels utilized in our terminal or logistics operations, which allows us to optimally manage our LNG supply

We expect to begin to source a portion of our LNG from our modular floating liquefaction facilities, which we refer to as "Fast LNG" or "FLNG." Our first FLNG facility began producing LNG in July 2024.

Following the anticipated sale of our Miami Facility, we expect to continue sourcing LNG from third parties and for a portion of our supply to be generated by our first FLNG unit.

The Terminals and Infrastructure segment includes all terminal operations in Jamaica, Puerto Rico, Mexico and Brazil, as well as vessels utilized in our terminal or logistics operations.

We centrally manage our LNG supply and the deployment of our vessels utilized in our terminal or logistics operations, which allows us to optimally manage our LNG supply and fleet.

Our Ships segment includes all vessels which are leased to customers under long-term arrangements.

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In March 2024, o ur contract to provide emergency power services to support the grid stabilization project was terminated.

We believe that there are remedies available under our customer contract, and we are currently in pursuit of these remedies.

As the result of this process is uncertain, any transaction price associated with closing this contract has been fully constrained.

In March 2024, we completed a suite of transactions that included the sale of turbines and related equipment deployed to support the grid stabilization project to PREPA under an Asset Purchase Agreement ("APA").

We are pursuing a $659 million request for equitable adjustment related to the early termination of our contract.

The actual amount of any such adjustment and the timing of any related payments may be materially different than management’s current estimate.

As a result, the Company cannot offer any assurance as to the actual amount that may be recovered pursuant to such request or subsequent claim, if any.

As the outcome of this process is uncertain, we have not recognized any revenue associated with the close out of our contract.

In March 2024, we completed a series of transactions that included the sale of turbines and related equipment deployed to support the grid stabilization project to PREPA under an Asset Purchase Agreement ("APA").

The purchase price was $306.6 million, and the APA includes an option for PREPA to purchase three additional turbines for additional purchase price of $65.7 million.

We recognized a loss of $77.5 million in Loss on sale of assets, net in the Condensed Consolidated Statements of Operations and Comprehensive Income.

We recognized a loss of $77.5 million in Loss on sale of assets, net in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

In the first quarter of 2024, we were also awarded a new gas sale agreement with PREPA to supply up to 80 TBtu annually to PREPA's gas-fired power plants, including to the turbines that were sold pursuant to the APA.

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In the fourth quarter of 2021, we began commercial operations at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”).

The La Paz Facility also supplies our gas-fired power units located adjacent to the La

Paz Facility (the “La Paz Power Plant”) and could have a maximum capacity of up to 135MW of power.

The La Paz Facility also supplies our gas-fired power units located adjacent to the La Paz Facility (the “La Paz Power Plant”) and could have a maximum capacity of up to 135MW of power.

We placed the La Paz Power Plant into service in the third quarter of 2023.

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This facility has liquefaction capacity of approximately 8,300 MMBtu of LNG per day and enables us to produce LNG for sales directly to industrial end-users in southern Florida, including Florida East Coast Railway via our train loading facility, and other customers throughout the Caribbean using ISO containers.

On June 30, 2024, the Company entered into a definitive agreement to sell its Miami Facility for $62 million.

The transaction is expected to close in the third quarter of 2024 subject to customary terms and conditions.

Our LNG Supply and Cargo Sales

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2) additional LNG supply contracts expected to commence in 2027;

3) our Miami Facility;

and 3) supply from our own Fast LNG production.

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LNG facilities, each with a 20-year term, which are expected to commence in 2027.

Finally, we plan to commence production from our own Fast LNG facilities upon the completion of commissioning in 2024 .

Finally, we plan to commence production from our own Fast LNG facilities, the first of which began to produce LNG in July 2024 .

We plan to expand that capacity when additional Fast LNG units come online.

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The majority of our LNG supply contracts are based on a natural gas-based index, Henry Hub, plus a contractual spread.

exposure to fluctuations in natural gas prices as our pricing in contracts with customers is largely based on the Henry Hub index price plus a fixed fee component.

We limit our exposure to fluctuations in natural gas prices as our pricing in contracts with customers is largely based on the Henry Hub index price plus a fixed fee component.

Additionally, with our own Fast LNG production, we plan to further mitigate our exposure to variability in LNG prices.

In 2022 and 2023, our revenue and results of operations have benefited from selling cargos into the global LNG market.

In 2022 and 2023, our revenue and results of operations benefited from selling cargos into the global LNG market.

As FLNG facilities commence production, our long-term strategy is to sell substantially all cargos produced to customers on a long-term, take-or-pay basis through our downstream terminals.

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The results of operations of vessels utilized in our terminal operations are reflected in the Terminals and Infrastructure segment.

In August 2022, we completed a transaction (the “Energos Formation Transaction”) with an affiliate of Apollo Global Management, Inc., pursuant to which we transferred ownership of 11 vessels to Energos in exchange for approximately $1.85 billion in cash and a 20% equity interest in Energos.

In August 2022, we completed a transaction (the “Energos Formation Transaction”) with an affiliate of Apollo Global Management, Inc., pursuant to which we transferred ownership of eleven vessels to Energos in exchange for approximately $1.85 billion in cash and a 20% equity interest in Energos.

Ten of the vessels were subject to current or future charters with NFE and one vessel (the Nanook ) was not subject to a future NFE charter.

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As a result, these ten vessels continue to be recognized on our Consolidated Balance Sheet as Property, plant and equipment, and the proceeds are recognized as debt.

Consistent with this treatment as a failed sale leaseback, (i) the third party charter revenues continue to be recognized by us as Vessel charter revenue;

(ii) the costs of operating the vessels is included in Vessel operating expenses for the remaining terms of the third-party charters and (iii)

such revenues are included as part of debt service for the sale leaseback financing debt and are included in additional financing costs within Interest expense, net.

Consistent with this treatment as a failed

sale leaseback, (i) the third party charter revenues continue to be recognized by us as Vessel charter revenue;

(ii) the costs of operating the vessels is included in Vessel operating expenses for the remaining terms of the third-party charters and (iii) such revenues are included as part of debt service for the sale leaseback financing debt and are included in additional financing costs within Interest expense, net.

In February 2024, we sold substantially all of our stake in Energos.

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our LNG terminal facility and power plant in Puerto Sandino, Nicaragua (“Puerto Sandino Facility”);

our LNG terminal (“Barcarena Facility”) and power plant (“Barcarena Power Plant”) located in Pará, Brazil;

our LNG terminal (“Barcarena Facility”) and power plants (“Barcarena Power Plant” and "PortoCem Power Plant") located in Pará, Brazil;

our LNG terminal located on the southern coast of Brazil ("Santa Catarina Terminal");

our LNG terminal (“Ireland Facility”) and power plant in Ireland, and our first green hydrogen project ("ZeroPark I").

our LNG terminal (“Ireland Facility”) and power plant in Ireland, our first green hydrogen project ("ZeroPark I") and Klondike Digital Infrastructure, our newly-launched power and data center infrastructure business ("Klondike").

We are also in active discussions to develop projects in multiple regions around the world that may have significant demand for additional power, LNG and natural gas, although there can be no assurance that these discussions will result in additional contracts or that we will be able to achieve our target revenue or results of operations.

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Our first FLNG unit has been installed and connected to the gas pipeline at Altamira, and we are in the process of commissioning the project.

While we experienced a delays in commissioning our first FLNG unit, which impacted our results of operations in this period and may impact our results in future periods, in July 2024, we began to produce LNG, and we expect to achieve run-rate production later in 2024.

In the first quarter of 2024, we executed an agreement with CFE to supply natural gas to an onshore liquefied natural gas terminal with up to two 1.4 MTPA FLNG units.

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Coast Guard to obtain our deepwater port license application for this facility.

The facility will be capable of

exporting up to approximately 145 billion cubic feet of natural gas per year, equivalent to approximately 2.8 MTPA of LNG.

The facility will be capable of exporting up to approximately 145 billion cubic feet of natural gas per year, equivalent to approximately 2.8 MTPA of LNG.

We have been in discussions with Petróleos Mexicanos (“Pemex”) to form a long-term strategic partnership to develop the Lakach deepwater natural gas field for Pemex to supply natural gas to Mexico's onshore domestic market and for NFE to produce LNG for export to global markets.

1 unchanged sentence

Puerto Sandino Facility

We are developing an offshore liquefied natural gas receiving and storage facility off the coast of Puerto Sandino, Nicaragua, as well as an onshore regasification facility.

We are developing a liquefied natural gas receiving, transloading and regasification facility in Puerto Sandino, Nicaragua, as well as a pipeline connecting the facility with our Puerto Sandino Power Plant.

We have entered into a 25-year PPA with Nicaragua’s electricity distribution companies, and we expect to utilize approximately 57,000 MMBtu from LNG per day to provide natural gas to the Puerto Sandino Power Plant in connection with the 25-year power purchase agreement.

As part of our long-term partnership with the local utility, we are evaluating solutions to optimize power generation efficiency and allow for additional electrical capacity in a market that is underserved.

We expect to complete this optimization in 2024.

As part of our long-term strategy, we are evaluating solutions to optimize power generation and delivery to other markets, connected to our power plant through a regional transmission line starting in 2025.

Barcarena Facility

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We have entered into a 15-year gas supply agreement with a subsidiary of Norsk Hydro ASA for the supply of natural gas to the Alunorte Alumina Refinery in Pará, Brazil, through our Barcarena Facility.

We substantially completed our Barcarena Facility in 2022 and expect to commence operations, including delivery to the Alunorte Alumina Refinery in the first half of 2024.

We substantially completed our Barcarena Facility in 2022 and expect to commence operations, including delivery to the Alunorte Alumina Refinery in the second half of 2024.

The Barcarena Facility will also supply our new 630MW combined cycle thermal power plant to be located in Pará, Brazil (the “Barcarena Power Plant”).

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("PortoCem"), a wholly-owned subsidiary of Ceiba Fundo de Investimento em Participações Multiestratégia- Investimento no Exterior ("Ceiba Energy") in exchange for newly issued 4.8% NFE redeemable Series A Convertible Preferred Stock.

PortoCem is the owner of a 15-year 1.6GW power power purchase agreement in Brazil.

We have received approval to transfer the 1.6 GW capacity reserve contract to a site owned by NFE that is adjacent to the Barcarena Facility, where NFE will build a power plant to supply the capacity reserve contract using gas from the Barcarena Facility.

PortoCem is the owner of a 15-year 1.6GW capacity reserve contract in Brazil.

We have received approval to transfer the 1.6 GW capacity reserve contract to a site owned by NFE that is adjacent to the Barcarena Facility, where NFE will build the PortoCem Power Plant to supply the capacity reserve contract using gas from the Barcarena Facility.

We expect to begin delivering electricity under the acquired capacity reserve contract in July 2026.

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The Santa Catarina Facility is located on the southern coast of Brazil and consists of an FSRU with a processing capacity of approximately 500,000 MMBtu from LNG per day and LNG storage capacity of up to 138,000 cubic meters.

We are developing a 33-kilometer, 20-inch pipeline that connects the Santa Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A.

We have developed a 33-kilometer, 20-inch pipeline that connects the Santa Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A.

(“TBG”) pipeline via an interconnection point in the municipality of Garuva.

The Santa Catarina Facility and associated pipeline are expected to have a total addressable market of 15 million cubic meters per day.

We expect to complete our Santa Catarina Facility and commence operations in the first half of 2024.

We expect to complete commissioning of our Santa Catarina Facility and commence operations in the second half of 2024.

Ireland Facility

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In the third quarter of 2023, An Bord Pleanála, Ireland's planning commission, denied our application for the development of an LNG terminal and power plant.

challenging this decision.

We are challenging this decision.

The continued development of this project is uncertain and there are multiple risks, including regulatory risks, that could preclude the development of this project, and the results of these risks could have a material effect on our results of operations.

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In total, ZeroPark I is expected to produce up to 86,000 kg of clean hydrogen per day, or approximately 31,000 TPA.

We have commenced design, engineering and permitting for ZeroPark I and expect to commence operations on the first phase in the first half of 2025.

We have commenced design, engineering and permitting for ZeroPark I and expect to commence operations on the first phase in 2025.

Additionally, we have secured a binding offtake commitment for the clean hydrogen produced at ZeroPark I.

Once completed, we expect ZeroPark I to be the largest green hydrogen plant in the United States.

Recent Developments

The Company recently launched Klondike, a power and data center development business dedicated to working with hyperscale customers to build and operate data centers.

This venture comes in response to a significant need for turnkey digital infrastructure to support the next stage of explosive growth in artificial intelligence.

Klondike will employ independent power sources that utilize behind-the-meter on-site power.

This innovative approach is designed to address all major constraints of digital infrastructure development, providing grid stability, significant transmission capacity, power reliability, energy cost savings, and scalability.

This approach not only reduces the demand for power from the grid but also contributes power back to it.

Klondike is currently developing a geographically diverse portfolio of data center sites to satisfy the requirements of hyperscale users.

Klondike has more than 1,000 acres of developable land across sites in Brazil, Ireland, and the United States that it either owns or leases.

These locations have large existing power plants or permits in process to build several gigawatts of power, connectivity to fiber networks, access to transmission and water.

Other Matters

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On July 31, 2023, FERC issued an order stating that it would not take action to prevent the construction and operation of the pipeline and interconnect and on January 30, 2024, FERC reaffirmed the order allowing the construction and operation to continue.

Results of Operations – Three Months Ended March 31, 2024 compared to Three Months Ended December 31, 2023 and Three Months Ended March 31, 2023

Results of Operations – Three Months Ended June 30, 2024 compared to Three Months Ended March 31, 2024 and Six Months Ended June 30, 2024 compared to Six Months Ended June 30, 2023

Performance of our two segments, Terminals and Infrastructure and Ships, is evaluated based on Segment Operating Margin.

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Consolidated Segment Operating Margin is mathematically equivalent to Revenue minus Cost of sales (excluding depreciation and amortization reflected separately) minus Operations and maintenance minus Vessel operating expenses, each as reported in our financial statements.

We believe this non-GAAP measure, as we have defined it, offers a useful supplemental measure of the overall performance of our operating assets in evaluating our

profitability in a manner that is consistent with metrics used for management’s evaluation of the overall performance of our operating assets.

We believe this non-GAAP measure, as we have defined it, offers a useful supplemental measure of the overall performance of our operating assets in evaluating our profitability in a manner that is consistent with metrics used for management’s evaluation of the overall performance of our operating assets.

Consolidated Segment Operating Margin is not a measurement of financial performance under GAAP and should not be considered in isolation or as an alternative to Gross margin, income from operations, net income, cash flow from operating activities or any other measure of performance or liquidity derived in accordance with GAAP.

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Investors are encouraged to review the related GAAP financial measures and the reconciliation of the non-GAAP financial measure to our Gross margin, and not to rely on any single financial measure to evaluate our business.

The tables below present our segment information for the three months ended March 31, 2024, December 31, 2023 and March 31, 2023:

The tables below present our segment information for the three months ended June 30, 2024 and March 31, 2024, and for the six months ended June 30, 2024 and June 30, 2023:

Three Months Ended June 30, 2024

(in thousands of $) Terminals and

Infrastructure Ships Total Segment Consolidation

and Other (3)

Total revenues $ 385,428 $ 42,578 $ 428,006 $ — $ 428,006

Cost of sales (1)(2)

221,860 — 221,860 — 221,860

Vessel operating expenses (4)

— 8,503 8,503 — 8,503

Operations and maintenance (4)

39,292 — 39,292 — 39,292

Deferred earnings from contracted sales (5)

90,000 — 90,000 (90,000) —

Segment Operating Margin $ 214,276 $ 34,075 $ 248,351 $ (90,000) $ 158,351

Three Months Ended June 30, 2024

(in thousands of $) Consolidated

Gross margin (GAAP) $ 120,938

Depreciation and amortization 37,413

Consolidated Segment Operating Margin (Non-GAAP) $ 158,351

Three Months Ended March 31, 2024

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Consolidated Segment Operating Margin (Non-GAAP) $ 384,260

Three Months Ended December 31, 2023

Six Months Ended June 30, 2024

(in thousands of $) Terminals and

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107,840 — 107,840 — 107,840

Deferred earnings from contracted sales (5)

90,000 — 90,000 (90,000) —

Segment Operating Margin $ 564,348 $ 68,263 $ 632,611 $ (90,000) $ 542,611

Three Months Ended December 31, 2023

Six Months Ended June 30, 2024

(in thousands of $) Consolidated

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Consolidated Segment Operating Margin (Non-GAAP) $ 542,611

Three Months Ended March 31, 2023

Six Months Ended June 30, 2023

(in thousands of $) Terminals and

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Segment Operating Margin $ 641,575 $ 133,076 $ 774,651 $ (129,983) $ 644,668

Three Months Ended March 31, 2023

Six Months Ended June 30, 2023

(in thousands of $) Consolidated

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Consolidated Segment Operating Margin (Non-GAAP) $ 644,668

(1) Cost of sales in our segment measure only includes realized gains and losses on derivative transactions that are economic hedges of our commodity purchases and sales.

For the three months ended March 31, 2024, December 31, 2023 and March 31, 2023, Terminals and Infrastructure does not include unrealized mark-to-market gains (losses) of derivative transactions of $–, 1.5 million and $111.1 million, respectively.

In the first quarter of 2023, a realized gain of $146.1 million were recognized as a reduction to Cost of sales in the segment measure.

(2) Cost of sales is presented exclusive of costs included in Depreciation and amortization in the Condensed Consolidated Statements of Operations and Comprehensive Income .

(3) Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to the Company's ownership of the common units of Hilli LLC in the segment measure, prior to the disposition to this investments, and exclusion of the unrealized mark-to-market gain or loss on derivative instruments.

(1) Cost of sales in our segment measure only includes realized gains and losses on derivative transactions that are economic hedges of our commodity purchases and sales, and realized gains of $141.9 million for the six months ended June 30, 2023 were recognized as a reduction to Cost of sales in the segment measure.

No such transactions were completed in 2024.

The Company recognized unrealized losses of $108.3 million on the mark-to-market value of derivative transactions for the six months ended June 30, 2023, and these losses reconcile Cost of sales in the segment measure to Cost of sales in the Condensed Consolidated Statements 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 $6.2 million for the six months ended June 30, 2023 are shown as a reduction to Cost of sales in the segment measure.

(2) Cost of sales is presented exclusive of costs included in Depreciation and amortization in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) .

(3) Consolidation and Other adjusts for the inclusion of deferred earnings on contracted LNG sales of $90,000.

The effective share of revenues, expenses and operating margin attributable to the Company's ownership of the common units of Hilli LLC in the segment measure, prior to the disposition to this investment, as well as unrealized mark-to-market gain or loss on derivative instruments, are also removed.

(4) Operations and maintenance and Vessel operating expenses are directly attributable to revenue-producing activities of our terminals and vessels and are included in the calculation of Gross margin defined under GAAP.

(5) Deferred earnings from contracted sales represent forward sales transactions that were contracted in the current period and prepayment for these sales was received.

Revenue will be recognized in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) when delivery under these forward sales transactions is completed in the third and fourth quarters of 2024.

Terminals and Infrastructure Segment

Three Months Ended,

(in thousands of $) March 31, 2024 December 31, 2023 Change March 31, 2023 Change

(in thousands of $) June 30, 2024 March 31, 2024 Change

Total revenues $ 385,428 $ 647,737 $ (262,309)

1 unchanged sentence

Operations and maintenance 39,292 68,548 (29,256)

Deferred earnings from contracted sales 90,000 — 90,000

Segment Operating Margin $ 214,276 $ 350,072 $ (135,796)

Six Months Ended,

(in thousands of $) June 30, 2024 June 30, 2023 Change

Total revenues $ 1,033,165 $ 998,112 $ 35,053

Cost of sales (exclusive of depreciation and amortization) 450,977 296,169 154,808

Operations and maintenance 107,840 60,368 47,472

Deferred earnings from contracted sales 90,000 — 90,000

Segment Operating Margin $ 564,348 $ 641,575 $ (77,227)

Total revenue

Total revenue for the Terminals and Infrastructure Segment decreased by $47.3 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023, and total revenue for the Terminals and Infrastructure Segment increased by $145.1 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023.

The decrease in revenue in the first quarter of 2024 when compared to the fourth quarter of 2023 was primarily attributable to decreases in the market price of natural gas.

The average Henry Hub index pricing used to invoice our downstream customers decreased by 22% for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023.

Volumes delivered to downstream terminal customers decreased from 22.2 TBtus in the fourth quarter of 2023 to 22.0 TBtu in the first quarter of 2024.

The increase in revenue in the first quarter of 2024 when compared to the first quarter of 2023 was primarily attributable to increased volumes delivered to our downstream customers, partially offset by reduced market pricing of natural gas.

• For the three months ended March 31, 2024, volumes delivered to downstream customers were 22.0 TBtu as compared to 12.1 TBtu for the three months ended March 31, 2023.

In 2023, we began to support the grid stabilization project in Puerto Rico, commissioning power generation assets in the second and third quarters of 2023, and the increase in volumes in the first quarter of 2024 is primarily attributable to additional sales in Puerto Rico.

Our customer terminated the grid stabilization project in the first quarter of 2024, but we continue to sell volumes into these power plants under a new island-wide gas sale agreement signed with PREPA that will allow us to sell up to 80 TBtus annually.

• The Company had no cargo sales for the three months ended March 31, 2024 as we were able to utilize all volumes under our supply contracts in our downstream terminal operations.

Revenue from cargos sales was $349.3 million for the three months ended March 31, 2023.

• The average Henry Hub index pricing used to invoice our downstream customers decreased by 35% for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023.

Total revenue for the Terminals and Infrastructure Segment decreased by $262.3 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024.

The decrease was primarily driven by decreases to revenue earned in our Puerto Rican operations after the termination of our contract to support the grid stabilization project late in the first quarter of 2024.

Additionally, volumes delivered to downstream terminal customers decreased from 22.0 TBtu in the first quarter of 2024 to 20.2 TBtu in the second quarter of 2024, which was primarily due to contract termination and maintenance in our Puerto Rico operations.

The average Henry Hub index pricing used to invoice our downstream customers decreased by 15% for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024.

Total revenue for the Terminals and Infrastructure Segment increased by $35.1 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023, and the increase in revenue was primarily attributable to the following:

• For the six months ended June 30, 2024, volumes delivered to downstream customers were 42.1 TBtu as compared to 26.1 TBtu for the six months ended June 30, 2023.

We delivered gas for two and half months for the

grid stabilization project in Puerto Rico during the first half of 2024, while the project was just ramping up during the second quarter of 2023.

• In the third quarter of 2023, we started providing operations and maintenance services to PREPA's thermal generation assets recognizing $109.6 million of revenue during the six months ended June 30, 2024.

Although we delivered significantly higher volumes in the current year, our revenue was impacted by lower Henry Hub pricing and lower cargo sale revenue.

• The average Henry Hub index pricing used to invoice our downstream customers decreased by 25% for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023.

• The Company had $24.5 million in cargo sales for the six months ended June 30, 2024.

Revenue from cargos sales was $617.1 million for the six months ended June 30, 2023

Cost of sales

Cost of sales includes the procurement of feedgas or LNG, as well as shipping and logistics costs to deliver LNG or natural gas to our facilities.

Our LNG and natural gas supply are purchased from third parties or converted in our Miami Facility.

Costs to convert natural gas to LNG, including labor, depreciation and other direct costs to operate our Miami Facility are also included in Cost of sales.

Cost of sales includes the procurement of feed gas or LNG, as well as shipping and logistics costs to deliver LNG or natural gas to our facilities.

Historically, our LNG and natural gas supply has been purchased from third parties or converted in our Miami Facility.

Following the anticipated sale of our Miami Facility, we expect to continue sourcing LNG from third parties and for a portion of our supply to be generated by our first FLNG unit.

Costs to convert natural gas to LNG, including labor, depreciation and other direct costs to operate our liquefaction facilities are also included in Cost of sales.

Starting in the third quarter of 2023, our subsidiary, Genera, began to provide operations and maintenance services to PREPA's thermal generation assets, and cost to provide these services is included in Cost of sales.

Under our contract with PREPA, we pass all of these costs onto PREPA, and such billings are recognized as revenue.

Cost of sales decreased by $30.9 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023.

We incurred additional development service costs of $19.6 million in the fourth quarter of 2023.

When we perform these services for our customers, such costs are reimbursed and revenue is recognized as services are performed.

Our cost to deliver natural gas volumes decreased to $6.96 per MMBtu for the three months ended March 31, 2024 from $7.08 per MMBtu for the three months ended December 31, 2023.

Cost of sales increased by $155.3 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023, which was attributable to the following:

• Realized gain of $146.1 from the settlement of a commodity swap transaction, entered into as an economic hedge to reduce the market risks associated with commodity prices, was included as reduction of cost of sales in the first quarter of 2023.

Cost of sales decreased by $7.3 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024, which was attributable to lower cost of gas purchased and volumes delivered.

We delivered 8% less volumes to our downstream terminal customers during the three months ended June 30, 2024 compared to the three months ended March 31, 2024.

Our cost to deliver natural gas volumes decreased to $6.42 per MMBtu for the three months ended June 30, 2024 from $6.96 per MMBtu for the three months ended March 31, 2024.

After our FLNG asset is fully commissioned and operational, we expect to be able to produce materially cheaper LNG than the LNG purchased under our supply contracts.

Cost of sales increased by $154.8 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023, which was attributable to the following activity:

• In the six months ended June 30, 2023, realized gains of $141.9 million from the settlement of commodity swap transactions, entered into as an economic hedge to reduce the market risks associated with commodity prices, were included as reduction of cost of sales in the segment measure.

For segment performance measures, unrealized mark to market gains and losses are excluded until settled.

We had no settlements of commodity derivative transactions in the first quarter of 2024.

• In the first quarter of 2024, we did not have any cargo sales and we delivered higher volumes to our downstream terminal customers in the current period as compared to the three months ended March 31, 2023.

delivered more volumes to our downstream customers, our pricing to purchase LNG for delivery to such customers decreased to $6.96 per MMBtu for the three months ended March 31, 2024 from $7.23 per MMBtu for the three months ended March 31, 2023.

No such transactions occurred in the current period.

• We incurred increased cost of LNG purchased from third parties for sale to our downstream customers of $71.1 million during the six months ended June 30, 2024 due to increased volumes delivered.

We delivered 61% more volume to our downstream terminal customers in the current period.

While we delivered significantly more volumes to our downstream customers, our pricing to purchase LNG for delivery to such customers was lower, decreasing to $6.65 per MMBtu for the six months ended June 30, 2024 from $7.66 per MMBtu for the six months ended June 30, 2023.

• Vessel costs increased by $47.3 million, for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023.

In 2023, we chartered additional vessels to enable us to rapidly have the infrastructure available to deliver additional LNG to Puerto Rico to support the grid stabilization contract.

In future periods, we expect our vessel costs to decrease as we optimize our supply chain to Puerto Rico with fewer and less costly vessels.

We were also able to sub-charter certain vessels for a portion of the current period, earning incremental charter revenue.

• We recognized additional payroll and other operating costs of $47.6 million to provide services under Genera's operations and maintenance contract;

these costs are passed onto PREPA.

The weighted-average cost of our LNG inventory balance to be used in our operations as of March 31, 2024 and December 31, 2023 was $7.10 per MMBtu and $7.33 per MMBtu, respectively.

No such costs were incurred during the six months ended June 30, 2023 as our contract commenced on July 1, 2023.

• We incurred decreased cost of LNG purchased from third parties for LNG cargo sales of $162.2 million during the six months ended June 30, 2024 as our LNG cargo sale activity has been significantly lower in the first half of 2024.

The weighted-average cost of our LNG inventory balance to be used in our operations as of June 30, 2024 and December 31, 2023 was $7.30 per MMBtu and $8.09 per MMBtu, respectively.

Operations and maintenance

Operations and maintenance includes costs of operating our facilities, exclusive of costs to convert that are reflected in Cost of sales.

Operations and maintenance increased by $6.6 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023.

The increase was primarily attributable to maintenance, logistics and other costs incurred for operating our terminals and power plants.

Operations and maintenance increased by $41.9 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023 .

The increase was primarily due to additional lease cost for turbines leased to generate power at the Palo Seco Power Plant and San Juan Power Plant as part of the grid stabilization project in Puerto Rico.

In addition, there were higher vessel operating costs included in Operations and maintenance as additional vessels started to support our terminal operations in 2024 as compared to the three months ended March 31, 2023.

Operations and maintenance decreased $29.3 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024.

The decrease was primarily attributable to reduced operations, maintenance and lease costs of turbines to generate power as part of the grid stabilization project in Puerto Rico.

In conjunction with the sale of certain turbines to PREPA, we have terminated our leases of certain turbines and are no longer incurring costs to operate these turbines.

Operations and maintenance increased $47.5 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023 .

The increase was primarily due to additional operations and maintenance cost including lease of turbines as part of the grid stabilization project in Puerto Rico.

The project operated for two and a half months during the first half of 2024, while it was just ramping up during the second quarter of 2023.

Deferred earnings from contracted sales

In the second quarter of 2024, we completed forward sales receiving a prepayment from the buyer of $90.0 million.

The prepayment was based on the fair market value of these sales as compared to our supply cost, and our CODM includes these results in his evaluation of Terminals and Infrastructure operations for the second quarter of 2024.

Revenue for these sales will be recognized in our Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) as deliveries under this contract will occur in the third and fourth quarters of 2024.

Both the forward contracted sale and our supply contract are based on Henry Hub which mitigates the impact that changes in commodity pricing will have on our results of operations.

Ships Segment

Three Months Ended,

(in thousands of $) March 31, 2024 December 31, 2023 Change March 31, 2023 Change

(in thousands of $) June 30, 2024 March 31, 2024 Change

Total revenues $ 42,578 $ 42,584 $ (6)

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Segment Operating Margin $ 34,075 $ 34,188 $ (113)

Six Months Ended,

(in thousands of $) June 30, 2024 June 30, 2023 Change

Total revenues $ 85,162 $ 163,758 $ (78,596)

Vessel operating expenses 16,899 30,682 (13,783)

Segment Operating Margin $ 68,263 $ 133,076 $ (64,813)

Revenue in the Ships segment is comprised of operating lease revenue under time charters, fees for positioning and repositioning vessels as well as the reimbursement of certain vessel operating costs.

As of December 31, 2023 and March 31, 2024, three FSRUs and one LNG carrier were leased to customers under long-term arrangements.

As of June 30, 2024 , three FSRUs and one LNG carrier were leased to customers under long-term arrangements.

On March 15, 2023, we completed disposition of our investment in the common units of Hilli LLC, and after this point, the revenue, expenses and operating margin attributable to our 50% ownership of the Hilli are no longer included in our segment results.

In the first quarter of 2024, we sold the vessel Mazo , for a total consideration of $22.4 million resulting in a gain of $0.4 million.

The gain on sale is included in Loss on sale of assets, net , in the Condensed Consolidated Statements of Operations and Comprehensive Income .

The gain on sale is included in Loss on sale of assets, net , in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) .

Total revenue

Total revenue for the Ships segment decreased $20.7 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023.

Total revenue for the Ships segment remained consistent for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024 .

Subsequent to the Energos Formation Transaction, we continue to be, for accounting purposes, the owner of certain vessels included in the transaction, and as such, we continue to recognize revenue from the charter of these vessels to third parties.

The decrease in revenue was primarily driven by end of third-party charters of Winter and Princess during the fourth quarter of 2023.

Total revenue for the Ships segment decreased $55.3 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023.

Total revenue for the Ships segment decreased $78.6 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023.

After the disposition of our investment in the common units of Hilli LLC at the end of the first quarter of 2023, we no longer recognize revenue from the Hilli , decreasing revenue in the Ships segment.

Additionally the charters for four vessels concluded in 2023, lowering vessel revenue for the three months ended March 31, 2024 .

Additionally the charters for four vessels concluded in 2023, lowering vessel revenue for the six months ended June 30, 2024.

We are now utilizing these vessels in our operations.

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To the extent that these costs are a fixed amount specified in the charter, which is not dependent upon redelivery location, the estimated voyage expenses are recognized over the term of the time charter.

Vessel operating expenses for the three months ended March 31, 2024 were consistent with those incurred in the three months ended December 31, 2023.

Vessel operating expenses decreased $10.8 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023.

Vessel operating expenses remained consistent during the three months ended June 30, 2024 as compared to the three months ended March 31, 2024.

There were no changes to the vessels that comprise the Ships segment in the second quarter of 2024.

Vessel operating expenses decreased $13.8 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023 .

The decrease in vessel operating expenses was primarily due to lower costs related to the Hilli after the disposition our investment in the common units of Hilli LLC at the end of the first quarter of 2023.

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Other operating results

Three Months Ended,

(in thousands of $) March 31, 2024 December 31, 2023 Change March 31, 2023 Change

Three Months Ended, Six Months Ended,

(in thousands of $) June 30, 2024 March 31, 2024 Change June 30, 2024 June 30, 2023 Change

Selling, general and administrative $ 70,578 $ 70,754 $ (176) $ 141,332 $ 107,941 $ 33,391

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Selling, general and administrative includes compensation expenses for our corporate employees, employee travel costs, insurance, professional fees for our advisors, and screening costs for projects that are in initial stages and development is not yet probable.

Selling, general and administrative increased $22.7 million for the three months ended March 31, 2024, compared to the three months ended December 31, 2023.

During the quarter ended March 31, 2024, the Company recognized an additional allowance for uncollectible receivables of $11.6 million.

The allowance reduces outstanding receivables for certain customers to reflect the amount that the Company expects to receive.

We have also recognized $5.2 million of share-based compensation costs associated with RSUs issued.

No significant allowance or share-based compensation costs were recognized during the three months ended December 31, 2023.

Selling, general and administrative increased by $18.6 million for three months ended March 31, 2024 as compared to the three months ended March 31, 2023.

We incurred additional allowance for uncollectible receivables and share-based compensation costs associated with RSUs issued;

no share based compensation expense or allowance was recognized in the first quarter of 2023.

The remaining increase was due to additional professional fees incurred.

Selling, general and administrative remained consistent for the three months ended June 30, 2024, compared to the three months ended March 31, 2024.

The Company incurred increased share-based compensation expense, that were partially offset by decrease in bad debt expense.

We recognized an additional $14.7 million of share-based compensation expense for RSUs and other equity awards during the second quarter of 2024 as we recognized a full quarter of expense for RSUs granted during the first quarter of 2024.

During the first quarter of 2024, the Company recorded an additional allowance for uncollectible receivables of $11.6 million.

There was no such allowance recognized during the second quarter of 2024.

We also incurred lower payroll and professional fees in the second quarter of 2024.

Selling, general and administrative increased by $33.4 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023.

The increases were primarily due to increased share-based compensation expense.

We recognized $25.2 million of share-based compensation expense for RSUs and other equity awards during the first half of 2024;

no significant cost was recognized in the first half of 2023.

In addition, the allowance for bad debt increased by $11.6 million due to an additional allowance recorded during the three months ended March 31, 2024.

Transaction and integration costs

The Company did not incur significant transaction and integration costs for the three months ended March 31, 2024, December 31, 2023 and March 31, 2023.

We did not incur significant transaction and integration costs for the three or six months ended June 30, 2024 or six months ended June 30, 2023.

Depreciation and amortization

Depreciation and amortization decreased by $11.7 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023.

The decrease is primarily attributable to the end of the term of two acquired favorable charter contract intangibles in the fourth quarter of 2023, reducing amortization expense in the first quarter of 2024.

Depreciation and amortization increased by $16.1 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023.

The increase is primarily resulting from turbines placed into service as part of the grid stabilization project during the second and third quarters of 2023.

In addition, the Company placed the La Paz power plant into service in September 2023.

Depreciation and amortization decreased $13.1 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024.

We sold certain turbines and equipment to PREPA in the first quarter of 2024, and the decrease in depreciation was primarily a result of no longer owning these assets.

Depreciation and amortization increased $11.4 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023.

In 2023, we began to place assets in service as part of the grid stabilization project in Puerto Rico, including turbines leased for the Palo Seco Power Plant under a finance lease.

The increase is primarily resulting from depreciation of the leasehold improvements that were placed into service during the second and third quarters of 2023, prior to the sale of these assets in the first quarter of 2024.

Asset impairment expense

In December 2023, the Company recognized an impairment of $11.0 million in conjunction with the classification as held for sale of its vessel Mazo.

There was no impairment of assets during three months ended March 31, 2024 or March 31, 2023.

In December 2023, the Company recognized an impairment of $4.3 million in conjunction with the classification as the Miami Facility as held for sale in the second quarter of 2024.

There was no impairment of assets during three months ended March 31, 2024 or six months ended June 30, 2023.

Loss on sale of assets, net

During the three months ended March 31, 2024, the Company recognized a loss of $77.5 million from the sale of turbines and related equipment to the PREPA.

During the fourth quarter of 2023, we completed the sale of 100% of shares in two project companies in Brazil for a total gain of $21.5 million.

We did not have any losses on sales during the three months ended June 30, 2024 or six months ended June 30, 2023.

Interest expense

Interest expense increased by $0.4 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023.

The increase was primarily due to new 2029 Notes (defined below) .

Interest expense increased by $5.7 million for the three months ended March 31, 2024, as compared to the three months ended March 31, 2023.

The increase was primarily due to an increase in total principal outstanding due to additional principal balance outstanding.

The total principal balance on outstanding facilities was $7.2 billion as of March 31, 2024 as compared to total outstanding debt of $5.3 billion as of March 31, 2023.

Our borrowing costs increased by $58.9 million for the first quarter of 2024 as compared to the first quarter of 2023.

However, we have capitalized $53.2 million additional interest in current period (see Note 19 in our condensed consolidated financial statements).

Interest expense increased by $3.1 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024.

We have incremental borrowings under the PortoCem Bridge Loan and our new Turbine Financing (each as defined below), and much of this increased interest expense was capitalized.

Interest expense increased by $21.7 million for the six months ended June 30, 2024 , as compared to the six months ended June 30, 2023 .

The increase was primarily due to an increase in total principal outstanding due to additional borrowings and amortization of related debt issuance costs.

The total principal balance on outstanding facilities was $7.8 billion as of June 30, 2024 as compared to total principal outstanding of $5.5 billion as of June 30, 2023.

We capitalize a significant portion of our borrowing costs for development projects, and while the principal balances increased, the interest expense did not increase as significantly.

Other expense (income), net

Other expense (income), net was $19.1 million, $(13.6) million and $25.0 million for the three months ended March 31, 2024, December 31, 2023 and March 31, 2023, respectively.

The significant increase in Other expense recognized in the three months ended March 31, 2024 and December 31, 2023 was primarily due to unrealized foreign currency remeasurement losses in the first quarter of 2024 as compared to remeasurement gains in the fourth quarter of 2023.

Other expense recognized in the three months ended March 31, 2023 was primarily comprised of a $37.4 million loss on disposal of Hilli equity method investment.

This loss was partially offset by interest income, foreign currency remeasurement gains and gains on investments in equity securities.

Other expense (income), net was $47.4 million and $19.1 million for the three months ended June 30, 2024, and March 31, 2024, respectively.

Other expense (income), net was $66.5 million and $18.4 million for the six months ended June 30, 2024 and 2023, respectively.

Other expense recognized in the three months ended June 30, 2024 was primarily comprised of foreign currency losses due to remeasurement of USD denominated debt in our Brazil subsidiary.

Other expense recognized in the six months ended June 30, 2024 was primarily comprised of foreign currency remeasurement losses and loss on termination of leases of turbines used in the grid stabilization project in Puerto Rico partially offset by interest income.

Loss on extinguishment of debt

During the three months ended March 31, 2024, we recognized prepayment premium and unamortized financing costs of $7.9 million in connection with the prepayment of the Equipment Notes.

We also recognized a premium over the repurchase price of $1.9 million in connection with the cash tender offer to repurchase $375.0 million of the outstanding 2025 Notes.

We also recognized a premium over the

repurchase price of $1.9 million in connection with the cash tender offer to repurchase $375.0 million of the outstanding 2025 Notes.

We did not have any extinguishment transactions in the second quarter of 2024 or the first half of 2023.

Income (loss) from equity method investments

During the three months ended March 31, 2023, we recognized income of $4.0 million from our equity method investment in Energos and $6.0 million of income from our investment in the common units of Hilli LLC for the period prior to the completion of the disposition of our investment.

We recognized a loss from our investment in Energos of $2.8 million for the three months ended December 31, 2023.

In the first quarter of 2024, we sold substantially all of our stake in Energos resulting in no income or loss from equity method investments for the three months ended March 31, 2024.

During the first half of 2023, we recognized income of $6.3 million from our equity method investment in Energos and $6.0 million of income from our investment in the common units of Hilli LLC for the period prior to the completion of the disposition of this investment.

In the first quarter of 2024, we sold substantially all of our stake in Energos resulting in no income or loss from equity method investments for the three or six months ended June 30, 2024.

Tax provision

We recognized a tax provision for the three months ended March 31, 2024 of $21.6 million compared to a tax provision of $46.0 million for the three months ended December 31, 2023 and a tax provision of $29.0 million for the three months ended March 31, 2023.

The increase in tax provision recognized in the fourth quarter of 2023 was primarily driven by increase in valuation allowance against losses in foreign jurisdictions.

We recognized a tax provision for the three months ended June 30, 2024 of $3.4 million compared to a tax provision of $21.6 million for the three months ended March 31, 2024.

We recognized a tax provision of $25.1 million for the six months ended June 30, 2024 compared to a tax provision of $44.3 million for the six months ended June 30, 2023.

The decrease in the tax provision for the three and six months ended June 30, 2024 is mainly due to changes in pre-tax income in the US and foreign jurisdictions which resulted in correlative changes in tax expense in those jurisdictions.

Factors Impacting Comparability of Our Financial Results

Our historical results of operations and cash flows are not indicative of results of operations and cash flows to be expected in the future, principally for the following reasons:

• Our historical financial results do not reflect our Fast LNG solution that will lower the cost of our LNG supply.

We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 99% of our LNG volumes from third parties for the three months ended March 31, 2024.

• Our historical financial results do not reflect our Fast LNG solution which we expect will lower the cost of our LNG supply.

We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 99% of our LNG volumes from third parties for the six months ended June 30, 2024.

We anticipate that the deployment of Fast LNG liquefaction facilities will significantly lower the cost of our LNG supply and reduce our dependence on third-party suppliers.

We expect to deploy our first Fast LNG unit upon the completion of commissioning in 2024.

Though the commissioning of these facilities, particularly our first Fast LNG unit, was delayed from the initially anticipated date, which impacted our results of operations in this period and may impact our results in future periods, we began to produce LNG from our first Fast LNG unit in July 2024.

We plan to leverage the development process for the first unit in deploying future Fast LNG liquefaction facilities.

• Our historical financial results do not include significant projects that have recently been completed or are near completion.

Our results of operations for the three months ended March 31, 2024 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Power Plant, certain industrial end-users and our Miami Facility.

We have completed construction and commissioning of our Barcarena Facility and Santa Catarina Facility and expect to place these assets into service in 2024.

Our results of operations for the three and six months ended June 30, 2024 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Power Plant, certain industrial end-users and our Miami Facility.

While we anticipate the sale of our Miami Facility in the third quarter of 2024, we have completed construction and commissioning of our Barcarena Facility and Santa Catarina Facility and expect to place these assets into service in 2024.

We are also continuing to develop our Puerto Sandino Facility and Ireland Facility, and our current results do not include revenue and operating results from these projects.

Additionally, we began to deliver power to the Puerto Rican grid as part of the grid stabilization project in the second quarter of 2023.

In the first quarter of 2024, our contract was terminated and assets related to the grid

stabilization project were sold to PREPA.

Under our new island-wide gas sale agreement with PREPA, we will continue to supply gas to these power generation assets.

In the first quarter of 2024, our contract was terminated and assets related to the grid stabilization project were sold to PREPA.

Under our new island-wide gas sale agreement with PREPA, we continue to supply gas to these power generation assets.

• Our historical financial results include the results from our investments in the common units of Hilli LLC and Energos.

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We believe we will have sufficient liquidity from proceeds from recent borrowings, access to additional capital sources and cash flow from operations to fund our capital expenditures and working capital needs for the next 12 months and the reasonably foreseeable future.

Our significant capital projects, primarily our first FLNG unit, are nearing completion, and as with many capital projects, a significant portion of the overall capital spending becomes due near the completion of the project.

Our 2025 Notes mature on September 15, 2025.

If any of the 2025 Notes remain outstanding 60 days prior to this maturity date (the "Springing Maturity Date"), the outstanding principal under the Revolving Facility, Term Loan B and FLNG2 Term Loans (as defined within Note 26 to the financial statements) will become immediately due.

The aggregate principal amount of 2025 Notes outstanding as of June 30, 2024 is $875,000.

We have entered into a Backstop Agreement with a lender, pursuant to which we may, at our sole option, issue and sell to this lender (subject to the satisfaction of certain conditions) senior secured notes up to an aggregate principal amount sufficient to generate gross proceeds of $875 million with a term of at least three years from the closing date within a certain window prior to the Springing Maturity Date.

Proceeds received would be used to repurchase or redeem all outstanding 2025 Notes.

We expect the current working capital position to improve based on the following:

(1) expected cash flows generated from new gas sale agreements in Puerto Rico and Brazil (2) sales of our own LNG generated by our first deployed Fast LNG unit;

(3) we have fully funded the construction of our Barcarena Power Plant with new long-term financing in Brazil and we have commitments to fund substantially all of the the remaining cost of our onshore FLNG project at Altamira;

(1) expected cash flows generated from new gas sale agreements and volume growth in Puerto Rico, Mexico and Brazil (2) sales of our own LNG generated by our first deployed Fast LNG unit;

(3) we have fully funded the construction of our Barcarena Power Plant with new long-term financing in Brazil and we have commitments to fund substantially all of the remaining cost of our onshore FLNG project at Altamira;

(4) our credit agreements allow for proceeds from the sale of assets to be reinvested in our business, and we have significant non-core assets that could be used to fund our developments;

and (5) our relationships with certain significant vendors constructing our Fast LNG assets have allowed us to extend our payment terms to better align with the expected completion of our first Fast LNG project.

In addition, we are exploring capital raising and strategic alternatives for our business in Brazil, which may include a

merger transaction, sale of a minority interest and/ or initial public offering.

There can be no assurance that the exploration

of capital raising and strategic alternatives will result in any agreements or transactions, or that, if completed, any

agreements or transactions will be successful or on attractive terms.

(5) our relationships with certain significant vendors, including vendors constructing our Fast LNG assets, have allowed us to extend our payment terms to better align with the expected completion of our first Fast LNG project;

and (6) the anticipated sale of our Miami Facility in the third quarter of 2024.

In addition, we are exploring capital raising and strategic alternatives for our business in Brazil, which may include a merger transaction, sale of a minority interest and/ or initial public offering.

There can be no assurance that the exploration of capital raising and strategic alternatives will result in any agreements or transactions, or that, if completed, any agreements or transactions will be successful or on attractive terms.

We expect to fund our current operations and continued development of additional facilities through cash on hand, borrowings under our debt facilities, cash generated from certain sales and financing transactions and cash generated from operations .

We may also opportunistically elect to generate additional liquidity through future debt or equity issuances and asset sales to fund our developments and transactions.

From time to time, we may seek to repay, refinance or restructure all or a portion of our debt or to repurchase our outstanding debt through, as applicable, tender offers, exchange offers, open market purchases, privately negotiated transactions or otherwise.

From time to time, we may seek to repay, refinance or restructure all or a portion of our debt or to repurchase our outstanding debt through, as applicable, tender offers, redemptions, exchange offers, open market purchases, privately negotiated transactions or otherwise.

Such transactions, if any, will depend on a number of factors, including prevailing market conditions, our liquidity requirements and contractual requirements (including compliance with the terms of our debt agreements), among other factors.

Our remaining committed capital expenditures is approximately $1,619 million and includes remaining expenditures to complete our first Fast LNG project and our onshore liquefaction project at Altamira, as well as committed expenditures necessary to complete the Puerto Sandino Facility, Barcarena Facility, Barcarena Power Plant, Santa Catarina Facility and Beaumont Facility.

Our expectations of future liquidity needs and sources include numerous assumptions that are subject to various risks and uncertainties.

Refer to Note 2 – “Significant Accounting Policies” for further information on liquidity and “Item 1A.

Risk Factors” for risks and uncertainties that may cause our results to differ from our expectations, each in our Annual Report on Form 10-K.

Our remaining committed capital expenditures is approximately $1,446 million and includes remaining expenditures to complete our first Fast LNG project and our onshore liquefaction project at Altamira, as well as committed expenditures necessary to complete the Puerto Sandino Facility, Barcarena Facility, Barcarena and PortoCem Power Plants, and Santa Catarina Facility.

This does not include any capital expenditures related to Klondike.

We have secured financing commitments to continue to develop our onshore Altamira project and the Barcarena Power Plant, which represents approximately $673 million of our upcoming committed capital expenditures.

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We may also enter into other financing arrangements to generate proceeds to fund our developments.

As of March 31, 2024, we have spent approximately $128.6 million to develop the Pennsylvania Facility.

As of June 30, 2024, we have spent approximately $128.6 million to develop the Pennsylvania Facility.

Approximately $22.5 million of construction and development costs have been expensed as we have not issued a final notice to proceed to our engineering, procurement and construction contractors.

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We are committed to make cash payments in the future pursuant to certain contracts.

The following table summarizes certain contractual obligations, including principal and interest, in place as of March 31, 2024.

The following table summarizes certain contractual obligations, including principal and interest, in place as of June 30, 2024.

(in thousands of $) Total Less than Year 1 Years 2 to 3 Year 4 to 5 More than

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Long-term debt obligations

For information on our long-term debt obligations, see “—Liquidity and Capital Resources—Long-Term Debt” in our Annual Report.

The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of March 31, 2024.

For information on our long-term debt obligations, see “—Liquidity and Capital Resources—Long-Term Debt” in our Annual Report, and “—Long-Term Debt and Preferred Stock” .

The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of June 30, 2024.

A portion of our long-term debt obligations will be paid to Energos under charters of vessels included in the Energos Formation Transaction to third parties.

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Certain LNG purchase commitments are subject to conditions precedent, and we include these expected commitments in the table above beginning when delivery is expected assuming that all contractual conditions precedent are met.

For purchase commitments priced based upon an index such as Henry Hub, the amounts shown in the table above are based on the spot price of that index as of March 31, 2024.

We have construction purchase commitments in connection with our development projects, including our Fast LNG projects, Puerto Sandino Facility, Barcarena Facility, Santa Catarina Facility and Beaumont Facility.

For purchase commitments priced based upon an index such as Henry Hub, the amounts shown in the table above are based on the spot price of that index as of June 30, 2024.

Commitments included in the table above include commitments under engineering, procurement and construction contracts where a notice to proceed has been issued.

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Future minimum lease payments under non-cancellable lease agreements, inclusive of fixed lease payments for renewal periods we are reasonably certain will be exercised, are included in the above table.

Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space, gas turbines and a land lease.

The following table summarizes the changes to our cash flows for the three months ended March 31, 2024 and 2023, respectively :

Three Months Ended March 31,

Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space, and a land lease.

The following table summarizes the changes to our cash flows for the six months ended June 30, 2024 and 2023, respectively :

Six Months Ended June 30,

(in thousands of $) 2024 2023 Change

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Cash provided by operating activities

Our cash flow provided by operating activities was $70.1 million for the three months ended March 31, 2024, which decreased by $130.1 million from cash provided by operating activities of $200.1 million for the three months ended March 31, 2023.

Our net income for the three months ended March 31, 2024, when adjusted for non-cash items, decreased by $11.3 million from the three months ended March 31, 2023.

The decrease in cash provided by operating activities for the three months ended March 31, 2024 was mainly driven by increases in inventory and other changes in working capital.

Our cash flow provided by operating activities was $163.0 million for the six months ended June 30, 2024, which decreased by $340.9 million from cash provided by operating activities of $503.9 million for the six months ended June 30, 2023.

Our net income for the six months ended June 30, 2024, when adjusted for non-cash items, decreased by $175.2 million from the six months ended June 30, 2024.

The remaining decrease in cash provided by operating activities for the six months ended June 30, 2024 was primarily driven by increases to receivables.

We also settled a significant commodity swap during the first quarter of 2023, resulting in a significant cash inflow that did not recur during 2024.

Cash used in investing activities

Our cash flow used in investing activities was $219.8 million for the three months ended March 31, 2024, which decreased by $243.5 million from cash used in investing activities of $463.3 million for the three months ended March 31, 2023.

Cash outflows for investing activities during the three months ended March 31, 2024 were used primarily for the continued development of our Fast LNG project and construction of our Barcarena Power Plant.

Our cash flow used in investing activities was $882.7 million for the six months ended June 30, 2024, which decreased by $484.4 million from cash used in investing activities of $1,367.1 million for the six months ended June 30, 2023.

Cash outflows for investing activities during the six months ended June 30, 2024 were used primarily for continued development of our Fast LNG and the construction of the PortoCem Power Plant and Barcarena Power Plant.

Cash outflows were offset by proceeds of $306.6 million from the sale of turbines and related equipment to PREPA, $136.4 million from the sale of our equity method investment in Energos and $22.4 million from the sale of the Mazo .

Cash outflows for investing activities during the three months ended March 31, 2023 were used primarily for continued development of our Fast LNG project.

Cash outflows for investing activities during the six months ended June 30, 2023 were used primarily for continued development of our Fast LNG project and assets to service the grid stabilization project in Puerto Rico.

Cash outflows were offset by proceeds of $100.0 million from the sale of our equity method investment in Hilli LLC in the Hilli Exchange.

Cash provided by financing activities

Our cash flow provided by financing activities was $157.6 million for the three months ended March 31, 2024, which increased by $114.4 million from cash provided by financing activities of $43.2 million for the three months ended March 31, 2023.

Our cash flow provided by financing activities was $735.7 million for the six months ended June 30, 2024, which increased by $513.1 million from cash provided by financing activities of $222.6 million for the six months ended June 30, 2023.

In the first quarter of 2024 we issued $750.0 million of 2029 Notes with such borrowings primarily used to repay $375.0 million of the 2025 Notes and repay a portion of our outstanding balance on the Revolving Facility.

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We also received $284.4 million under the BNDES Credit Agreement, with such borrowings primarily used to repay the Barcarena Term Loan and fund development of the Barcarena Power Plant.

We also paid dividends of $32.3 million during the first quarter of 2024.

Our cash flow provided by financing activities for the three months ended March 31, 2023 included a dividend payment of $626.3 million that was made in January 2023.

Throughout the first quarter of 2023 we also borrowed under our expanded Revolving Facility for total additional borrowings of $700.0 million, with such borrowings primarily used to fund the ongoing development of our Fast LNG project.

In the second quarter of 2024, we borrowed $269.9 million to repay the PortoCem BTG Loan and begin the development and construction of a power plant to deliver under the capacity reserve contracts acquired in the PortoCem Acquisition.

Additionally, we borrowed $148.5 million under a promissory note secured by certain turbines owned by the Company .

Our cash flow provided by financing activities for the six months ended June 30, 2023 included a dividend payment of $626.3 million that was made in January 2023.

Throughout the first six months of 2023, we also borrowed under our expanded Revolving Facility for total additional borrowings of $741.6 million, with such borrowings primarily used to fund the ongoing development of our Fast LNG project.

We also borrowed $100.0 million under the Equipment Notes to support our grid stabilization project in Puerto Rico and $78.0 million of short-term borrowings under repurchase arrangements.

These Equipment Notes were refinanced by the Turbine Financing.

Long-Term Debt and Preferred Stock

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The tender offer was closed and the partial repurchase of the 2025 Notes was completed in the first quarter of 2024.

The premium over the repurchase price of $1.9 million was recognized as Loss on extinguishment of debt, net in the Condensed Consolidated Statements of Operations and Comprehensive Income.

The premium over the repurchase price of $1.9 million was recognized as Loss on extinguishment of debt, net in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

BNDES Term Loan

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We are able to borrow up to $355.6 million under the BNDES Credit Agreement, segregated into three tranches based on the use of proceeds ("BNDES Term Loan").

In the first quarter of 2024, lenders funded $273.4 million under the BNDES Credit Agreement.

In the first quarter of 2024, we borrowed $284.4 million under the BNDES Credit Agreement.

Each tranche bears a different rate of interest ranging from 2.61% to 4.41% plus the fixed rate announced by BNDES.

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we have provided a guarantee of the obligations under the EB-5 Loan Agreement.

In the three months ended March 31, 2024, an additional $36.3 million was funded under the EB-5 Loan Agreement.

PortoCem BTG Loan

As part of the PortoCem Acquisition, we assumed a term loan in the aggregate principal amount of BRL 141.4 million ($28.1 million based on rates in effect on the acquisition date) due December 2024, bearing interest at a rate equal to the one-day interbank deposit rate in Brazil plus 5.0% (the “PortoCem BTG Loan”).

Lenders under the PortoCem BTG Loan waived acceleration requirements in the event of a change in control in conjunction with the PortoCem Acquisition, and repayment of the PortoCem BTG Loan is now required upon the earlier of PortoCem obtaining additional financing or the original maturity date of December 2024.

We provided a parent company guarantee to the lenders under the PortoCem BTG Loan.

The PortoCem BTG Loan contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default.

No financial debt covenant compliance is required under this loan facility.

In April 2024, we repaid the PortoCem BTG Loan with proceeds from a short term credit note.

In the six months ended June 30, 2024, an additional $37.1 million was funded under the EB-5 Loan Agreement.

PortoCem Financings

As part of the PortoCem Acquisition, we assumed a term loan in the aggregate principal amount of R$141.4 million ($28.1 million based on rates in effect on the acquisition date) due December 2024, bearing interest at a rate equal to the one-day interbank deposit rate in Brazil plus 5.0% (the “PortoCem BTG Loan”).

Lenders under the PortoCem BTG Loan waived acceleration requirements in the event of a change in control in conjunction with the PortoCem Acquisition, and repayment of the PortoCem BTG Loan was required upon the earlier of PortoCem obtaining additional financing or the original maturity date of December 2024.

In April 2024, PortoCem and a syndicate of banks in Brazil entered into a commitment letter for R$2.9 billion of financing.

PortoCem received funding under a short term credit note of R$600.0 million ("PortoCem Credit Note") from this syndicate that was due in July 2024, and a portion of the proceeds was used to repay the PortoCem BTG Loan.

In May 2024, the PortoCem Credit Note was replaced by a bridge financing agreement that allows PortoCem to borrow up to R$2.9 billion due in October 2025 ("PortoCem Bridge Loan").

PortoCem initially borrowed R$1.5 billion ( $269.9 million based on rates in effect at June 30, 2024), and this initial funding was used to repay the PortoCem Credit Note and to begin the development and construction of a power plant to deliver under the capacity reserve contracts acquired in the PortoCem Acquisition.

The PortoCem Bridge Loan bears interest at the one-day interbank deposit futures rate in Brazil plus 4.25%, and no principal payments are required until maturity in October 2025.

The PortoCem Bridge Loan contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants.

The PortoCem Bridge Loan does not contain any restrictive financial covenants.

Turbine Financing

In May 2024, we executed a loan agreement with a lender to borrow $148.5 million under a promissory note secured by certain of our turbines (the “Turbine Financing”).

The Turbine Financing bears interest at 10.30% , and the principal is partially repayable in monthly installments over the 36-month term of the loan with the balance due upon maturity in June 2027.

The Turbine Financing contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants.

The Turbine Financing does not contain any restrictive financial covenants.

We were required to pay a deposit of approximately $6.0 million that will be held by the lender throughout the term of the borrowing.

Equipment Notes

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Principal outstanding as of the repayment date was $188.4 million, and we incurred a prepayment premium of 3%.

The prepayment premium and any unamortized financing costs of $7.9 million were recognized as Loss on extinguishment of debt, net in the Condensed Consolidated Statements of Operations and Comprehensive Income .

Debt and lease restrictions

We are required to comply with covenants under the Revolving Facility and letter of credit facility, including requirements to maintain Debt to Capitalization Ratio of less than 0.7:1.0, and for quarters in which the Revolving Facility is greater than 50% drawn, the Debt to Annualized EBITDA Ratio must be less than 4.0:1.0.

We were in compliance with all covenants as of March 31, 2024.

We were in compliance with all covenants as of June 30, 2024.

Critical Accounting Policies and Estimates

A complete discussion of our critical accounting policies and estimates is included in our Annual Report.

As of March 31, 2024 , there have been no significant changes to our critical accounting estimates since our Annual Report.

As of June 30, 2024 , there have been no significant changes to our critical accounting estimates since our Annual Report.

Recent Accounting Standards

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis