Decarbonisati n Technolo gy Powering the Transition to Sustainable Fuels & Energy February 2026 May 2023 Technolo gy Powering the Transition to Sustainable Fuels & Energy
US ENERGY TRANSITION RENEWABLE HYDROGEN & HYDROGEN SAFETY
DECARBONISATION OF REFINING VALUE CHAINS
AVIATION: eSAF OUTLOOK FOR 2026 SUSTAINABLE AVIATION AND MARINE FUELS
MARITIME: FORECAST & TRANSITION FUELS UTILISATION OF CAPTURED CARBON
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Contents
February 2026
5
Energy trilemma: refiners must plan to pivot Alan Gelder Wood Mackenzie
13 The US energy transition 2025 Nishadi Davis Wood
19 How advanced heat exchanger solutions can accelerate CCS Marcin Karas and Alexander Gernhardt Kelvion
25 A pivotal phase for shipping
Eirik Ovrum and Øyvind Sekkesæter DNV
33 Role of transitional fuels in decarbonising shipping Eddy Van Bouwel EvBo Consult
39 One hundred years of Fischer-Tropsch: Part 2 Dan Carter, Richard Pearson, and Andrew Coe Johnson Matthey
45 Hydrogen electrolyser technology advancements Stephen B Harrison sbh4 Consulting
50 2G ethanol as an industrial decarbonisation engine Tania Guha Engineers India Limited
56 Synthetic e-fuel production technologies Eser Dinçer Hafızoğlu, Tuğçe Özperçin, Aysel Zahidova, and Vahide Mutlu SOCAR Türkiye Research & Development and Innovation Inc 63 Advanced structured packing for economical decarbonisation Taylor Topham, Anand Vennavelli, and Zack Bondley Koch-Glitsch 68 CCS: how chemical tracers safeguard future of CO₂ storage Heinz Weidmann Tracerco
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A Safe Flight Toward Decarbonization Axens has developed extensive knowhow and industrial experience in the renewables field and now offers a complete portfolio for the transition to the bioeconomy, including several Sustainable Aviation Fuels pathways. www.axens.net
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Energy demand continues to grow, and coal, oil, and gas together still account for 80% of the world’s energy supply. Some observers use this to suggest that the energy transition is ineffective. We would rather highlight the progress made, while recognising the enormous scale of the task, which will now extend beyond 2050. The energy transition aims to achieve net zero by 2050. The first phase, over the past 20 years, was the switch from coal to more sustainable fossil gas, led by the US and the EU. Going forward, industry leaders are investing to reduce gas flaring and methane emissions during gas production and distribution. The UNFCCC considers carbon capture and storage (CCS) to be vital. CCS is already viable for enhanced oil recovery. Increasingly, it will be used to reduce carbon emissions from the combustion of hydrocarbons and, via direct air capture (DAC), to draw down carbon dioxide from the atmosphere. Yes, CCS does allow the extended use of hydrocarbons, but it is also key to the longer-term transition, supporting the switch from fossil to renewable hydrocarbon sources, along with the expansion of sustainable electricity generation. The IEA reports that electricity consumption comprised the highest growth in energy demand in 2024, with China making up more than half of that. Increases in cooling, the electrification of transport, and the rise of data centres all contribute to growing demand. However, IEA’s analysis also shows that 80% of the growth in global electricity generation was from sustainable sources, including solar, wind, and nuclear power. The balance between fossil fuel and renewable energy sources varies considerably. Electricity generation in several countries, particularly those blessed with hydroelectric power, is more than 90%. In other countries, fossil sources continue to prevail. Even then, China, India, and many emerging economies are investing heavily in renewable power for electricity generation. In countries along the East African Rift and elsewhere, geothermal energy is a viable option. Growth in renewable electricity is also critical for the transport sectors, which continue to rely on a chemical energy carrier, increasingly renewable hydrocarbons, ammonia, or hydrogen. IATA and IMO are pursuing ‘net zero by 2050’ strategies for sustainable aviation and shipping, respectively. Aviation requires energy-dense hydrocarbons, with IATA initially reliant on carbon offsets, while aviation fuels suppliers are investing in ‘drop-in’ renewable hydrocarbons for the longer term. In marine, LNG is available as a transition fuel, with methanol and ammonia emerging as longer-term, more sustainable options. Electrification of road transport is progressing in many advanced economies, but requires greater investment in transmission and charging infrastructure. In developing economies, the cost of electric vehicles is prohibitive; often, the priority for expanding electricity production is to power homes. Dr Robin Nelson
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Energy trilemma: refiners must plan to pivot How refiners can overcome today’s volatility – from geopolitical tensions to shifting trade dynamics – and turn uncertainty into competitive advantage
Alan Gelder Wood Mackenzie
Oil market surplus drives lower prices in 2026 Wood Mackenzie’s oil demand growth projections for 2025 were downgraded after the US administration declared ‘Liberation Day’ last April. The 2025 global Gross Domestic Product (GDP) was better than initially feared, comparable to 2024 levels, as tariff increases were paused and businesses frontloaded trade ahead of the tariff changes. China’s economic stimulus measures and a capital expenditure boom in artificial intelligence (AI) technology all provided support during 2025. However, we forecast growth will slow in 2026 as the impacts of tariffs are felt by US consumers and China faces internal and external headwinds. We believe that the US effective tariff rate has already peaked and will fall through 2026 and 2027 from new
bilateral trade deals with the US and trade flow optimisation. However, these factors are unable to deliver stronger global growth in 2026. The impact of weak global GDP growth is to keep 2026 global oil demand growth below 2025 levels at under 700 kb/d, as shown in Figure 1 . The key growth regions are ‘Other Asia Pacific’ and India, both of which are forecast to grow less than 200 kb/d annually. China’s oil demand growth is forecast to be weak as road transport fuels (gasoline and diesel) continue their decline due to vehicle electrification (as of the end of 2024, EVs represented almost 60% of new vehicle sales for passenger cars, and liquefied natural gas (LNG)/EVs accounted for almost 40% of new commercial vehicle sales), whereas jet fuel and petrochemical feedstocks show continued growth.
Demand growth by market, 2026
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Figure 1 Global oil demand growth and regional non-OPEC supply growth.
Source: Wood Mackenzie Macro Oils Service
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Net global CDU capacity additions (kb/d)
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Figure 2 Net global CDU capacity additions (kb/d) and global composite gross refining margin ($/bbl). Source: Wood Mackenzie Product Markets Service Short Term
As shown in Figure 1, non-OPEC supply growth is set to outpace global oil demand again in 2026 (as it did in 2025, driving the price of Dated Brent from a monthly average price of just under $80/bbl in January 2025 to the low $60s/ bbl in December). The supply growth is primarily from conventional projects in Latin America, led by Brazil and Guyana. It is therefore dependent upon the timing of project completion rather than the prevailing oil price. US tight oil production, however, is responsive to price, with modest production declines recorded during late 2025 and projected for 2026. However, US Gulf of Mexico projects and growth in Canada outweigh US tight oil declines, sustaining production growth in North America. The implication of this supply overhang is that oil prices are likely to weaken further in 2026. Q1 2026 is projected to be the low point at mid- to-high $50s/bbl for Dated Brent, with prices then recovering as refinery runs increase to satisfy Northern Hemisphere seasonal demand growth. In 2027, non-OPEC supply growth is outpaced by global oil demand growth, but declining US Lower 48 production supports a modest price recovery. 2026 is the floor for refining margins, with chemicals to remain in the doldrums The commercial performance of the refining sector is complex, given the product-specific demand dynamics, supply/demand balances, and trade flows. However, at the highest level, global refinery utilisation trends provide an
indication as to the aggregate performance of the refining sector. As shown in Figure 2 , net global crude distillation unit (CDU) capacity additions for 2026 are forecast at almost 1 million b/d, due to projects in Asia and the Middle East achieving commercial production, outweighing closures in Europe and the US. This indicates that net capacity additions outpace global demand growth. However, with 2026 demand growth dominated by petrochemical feedstocks, the tightness around the refining system will certainly ease unless there are unforeseen significant capacity outages. Transport fuel inventories are expected to build, particularly during Q1 2026 when oil prices are projected to weaken, enabling refiners to run harder than seasonal norms. The ramp-up of the new projects in the Middle East and India during Q1 2026 along with the return of the Dangote facility in Nigeria to normal operations after maintenance, normalises refining margins through 2026. We project 2026 to be the margin low point for the global refining industry, as there are limited capacity additions in 2027, while oil demand continues to rise. Rising global oil demand with limited capacity additions supports higher refinery utilisations, sustaining global refining margins at healthy levels until global oil demand peaks and starts to slowly decline in the early 2030s. The outlook for chemicals remains challenging. China continues its wave of capacity additions, which far outpace global demand growth, as several refineries transition from oil products
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Atlantic Basin petrochemical uplift vs. yields, by year
2024 Atlantic Basin petrochemical uplift by product group
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Ole ns and polyole ns showed the strongest uplift to margins with aromatics adding little or even negative value A - aromatics O -ole ns P -polyole ns AO -aromatics and ole ns etc.
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Petrochemicals yield of total products (wt%)
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Figure 3 Petrochemical net cash margin uplift ($/bl).
Source: Wood Mackenzie REM-Chemical s
to chemicals, given that China’s transport fuel demand is falling. In aggregate, annual ethylene capacity additions outpace demand growth for the next three years, preventing the typical cycle of margin trough and recovery. Any recovery is ‘L-shaped’, so it will not be quick, resulting in less competitive steam crackers across Europe and Asia remaining under threat of closure for some time. For commodity chemical companies, 2026 is a year to survive, with the hope that rationalisation is something that happens to others. Petrochemicals adding value to refining Despite the weak chemical margins,
petrochemicals are a source of value addition for the refining sector, as shown in Figure 3 . These charts show the value uplift expressed in net cash margin terms against petrochemical yield over recent years. The value uplift from petrochemicals was stronger in 2024 than in 2023, with 2021 a year the chemical sector will remember fondly, as it was the last year of high profitability. The charts show that typically the greater the yield of petrochemicals, the higher the value uplift, with the olefins/polyolefins value chain adding the most value. It is important to note that low yields of petrochemicals can destroy value, given the higher operating costs of such facilities.
2024 Atlantic Basin HVO GPW contribution and yields
2024 Atlantic Basin renewable fuel gross margins
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HVO gross margin contribution fell by 2.54 US$/bbl
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Figure 4 Liquid renewable GPW contribution and gross margins ($/tonne).
Source: Wood Mackenzie Refinery Evaluation Model and Liquid Renewable Fuels Service
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Figure 5 Integrated refinery petrochemical site net cash margin, 2024 ($/bbl).
Source: Wood Mackenzie Refinery Evaluation Model
Liquid renewables are also a source of value addition for the refining sector, despite credit prices having fallen during 2024. Figure 4 shows the disproportionate contribution to the Gross Product Worth (GPW) compared to the yield of hydrotreated vegetable oil (HVO) for Atlantic Basin refineries undertaking co-processing of bio-feedstocks. The chart also shows that North America enjoys higher gross margins than Europe for converting used cooking oil (UCO) into renewable diesel (HVO), sustainable aviation fuel (SAF), and bio-naphtha. Competitiveness is key Figure 5 shows the 2024 net cash margin profile for all refineries above 50,000 b/d capacity, incorporating contributions from liquid renewables and petrochemicals. The
most competitive assets are typically in North America, with European assets typically positioned in the second or third quartile. We have more than 15 years of history of such a chart, and the key points to note are: • First quartile and fourth quartile assets stay in their respective quartile. • Fourth quartile assets often continue to operate despite negative margins as they are national oil company (NOC) owned and perform a broader role within the local economy, often supplying subsidised fuels to the local population. • Second and third quartile assets often oscillate between quartiles depending upon the relative strength of product crack spreads (gasoline vs middle distillates) and light/heavy feedstock differentials.
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Emissions from IGCC
Rising EU ETS pricing will erode complex, high emission site’s margins. CBAM is only expected to provide minor relief.
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2024 Integrated Net Cash Margin (US$/bbl)
NWE Gross Brent FCC Margin, US$/bbl Global Composite Margin, US$/bbl
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Transaction candidates
Upcoming/recent closure
Figure 6 Gross margin and EU ETS forecast alongside 2024 European NCM vs emissions intensity quadrant. Source: Wood Mackenzie Refinery Evaluation Model and Product Markets Service
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Plan to pivot Demand for petrochemicals and liquid
• Feedstock differentials drive the slope of the curve, with the absolute level of refining margins determining the number of sites that are cash negative. With our outlook of medium-term demand growth outpacing capacity additions, global refinery utilisation and refining margins remain at healthy levels until peak oil demand is passed. Falling global demand pressures refinery throughput, lowering utilisation, and driving the commercial performance of competitively weak assets to margins that challenge their viability. European refineries are particularly exposed, as domestic demand is already declining. Figure 6 shows how much lower European gross refining margins are relative to the global composite. European refiners are further challenged by the cost of carbon emissions, with the EU Emissions Trading System (ETS) carbon price scheme projected to rise to more than €150 per tonne in the early 2030s. Each refinery is unique, but categorisation of assets into quadrants by integrated net cash margin and emissions intensity identifies the target attributes (high earnings and low emissions intensity). Competitive assets with high emissions intensity are to focus investments on emissions-reduction projects. Competitively weak assets have a dilemma: sustained crude oil processing may not be commercially viable within the next two to three major turnaround cycles, so they need to plan to pivot toward higher-value opportunities.
renewables, particularly SAF, is projected to grow strongly over the medium to long term, providing an opportunity in stark contrast to the declines projected for road fuels. Petrochemical integration is an essential feature of grassroots facilities and major upgrades planned for refineries in the Middle East and China. It is not a pragmatic opportunity for most competitively weak refining sites in Europe, as they are unable to provide sufficient feedstock for world-scale petrochemical facilities without a significant transformation (crude-to-chemicals facility) that would be very capital intensive. For European sites, pivoting means shifting to supplying liquid renewables, thereby becoming an integral part of the circular economy. SAF represents a strong growth potential, as shown in Figure 7 . An increasing number of economic unions, countries, and states within countries are adopting policies to support the uptake of SAF, with the EU adopting the most stringent policies in terms of the carbon intensity of the feedstock. The provision of SAF will depend on multiple technologies, as while HEFA-SAF technology is mature and investment is growing fast, there are limits to the availability of sustainable feedstocks and there will be competition from road fuel decarbonisation. The first commercial Alcohol-to-Jet (ATJ) plant is now operating. However, the availability of low-carbon-intensity ethanol represents a long-term challenge to the growth of this technology route. Biomass-to-
Liquid (BTL) project commercialisation offers a wide feedstock pool but remains technically challenging. Start- ups and new entrants dominate the e-SAF project landscape, but high e-SAF costs and project complexity slow project development. It is important to note that liquid renewables
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Figure 7 Global SAF demand forecast by fuel type.
Source: Wood Mackenzie Liquid Renewable Fuels Service
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are being commoditised, and that ReFuelEU does not require domestic production, making Europe an attractive target market for suppliers able to meet the stringent feedstock requirements. This commoditisation requires refiners not to forget the investment fundamentals: strong competitive positions are secured through supplying a local market processing an advantaged feedstock in an efficient, flexible facility. One size will certainly not fit all, but many sites deploying different technologies will be able to successfully adapt through the energy transition.
renewables to support stronger total demand for liquids and decarbonisation. • Trade policy around liquid renewable feedstocks, particularly in Asia, as this is a key source of UCO currently processed within Europe. • EU Carbon Border Adjustment Mechanism (CBAM) policy and regional support for the adaptation to liquid renewables and synthetic fuels.
Alan Gelder alan.gelder@woodmac.com
Things to watch The world is increasingly interconnected, so uncertainties around economic growth, geopolitical tensions, and trade policies ripple through the oil value chain. There are several things we are watching with respect to the medium term, notably: • Global economic growth – could it be weaker than expected due to stalling investment in view of policy uncertainty, or does the US Supreme Court limit the potency of US tariffs as a geopolitical weapon, supporting a return to greater investment? • OPEC+ behaviour – does the group continue with its pragmatism, or does it decide to go for market share, or end production easing and return to deeper cuts to lift prices? • Russia/Ukraine conflict and associated Russian infrastructure outages. • The pace of the energy transition, particularly around vehicle fuel efficiency and electrification mandates. Slower electrification will require higher volumes of liquid
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The US energy transition 2025
A year of momentum, volatility, and recalibration has led the US to start building an energy system that can meet rising demand and navigate global uncertainty
Nishadi Davis Wood
E nergy transitions rarely follow linear paths. They move in cycles of ambition, adjustment, and renewed direction as technology, markets, and policy interact in complex ways. In the US, 2025 became a defining year in that ongoing evolution. It was a year shaped by a recalibration of expectations and priorities amid rising demand, global instability, domestic political change, and persistent uncertainty around the policy frameworks meant to govern the transition. The year opened with unusual ambiguity. Much of the Inflation Reduction Act’s (IRA) long- awaited guidance had still not been finalised, leaving investors and developers unclear about qualification rules, credit calculations, prevailing wage requirements, and the boundaries of eligibility for emerging technologies. At the same time, signals from the incoming administration suggested that fiscal restraint, domestic manufacturing, and national energy security would weigh more heavily in policy decisions going forward. These early signals led to questions about whether the US would sustain the same pace in the transition to clean energy seen immediately after the IRA’s passage. By midyear, the One Big Beautiful Bill Act (OBBBA) provided the answer, reshaping the contours of federal clean energy policy. The legislation preserved several core credit structures but reduced their scope. It shortened qualification windows, tightened domestic content requirements, narrowed transferability provisions, and added stronger restrictions related to foreign entities of concern (US Congress, 2025). While these changes did not dismantle the IRA, they pulled back many of its most generous provisions and shifted the ground on which developers had been planning.
However, to characterise 2025 as a reversal would overlook the deeper momentum shaping the US energy system. Even as federal policy placed renewed emphasis on cost discipline and energy security, the broader ecosystem continued to advance the transition. Utilities pressed ahead with grid modernisation, developers restructured but did not abandon clean energy pipelines, and industrial players moved forward with decarbonisation strategies tied to competitiveness and long-term resilience. The national posture shifted toward pragmatism, but the underlying drivers of the transition remained firmly in place. Progress was shaped less by sweeping policy signals and more by practical realities, including long interconnection queues, prolonged permitting timelines, supply chain pressures, and a global environment that elevated reliability and energy security as central considerations. In this landscape, the transition did not stall; it evolved into a more measured, implementation-focused phase. The result is a transition still very much underway, but shaped by a more grounded understanding of how rapid technological change meets the realities of physical infrastructure and complex stakeholder expectations. Demand growth reshapes energy landscape For the first time in nearly 20 years, the US experienced sustained electricity demand growth across consecutive years. Energy Information Administration (EIA) data showed national consumption rising by roughly 2% in both 2024 and 2025, reversing a long period of stagnant demand that began in the mid-2000s. This growth was structural rather than cyclical, driven by several reinforcing forces ( US EIA, 2025d ) (see Figure 1 ).
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of several hundred megawatts, their impact on regional grids is becoming more pronounced. Interconnection queues authorities. Substation expansions, transformer procurement, and necessary transmission upgrades all faced lengthened across multiple balancing
Short-term energy outlook forecast
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Figure 1 US electricity demand growth 1990-2025. Source: (US EIA, 2025d)
Electric vehicle adoption continued to expand. Domestic manufacturing accelerated in response to industrial policy and global realignment of supply chains. And most significantly, the rapid expansion of data centres supporting artificial intelligence (AI) created a new class of large, continuously operating electricity customers. Data centres became one of the most consequential drivers of growth. Hyperscale campuses increasingly approached several hundred megawatts of capacity, functioning as round-the-clock industrial loads. According to the Department of Energy (DOE) and Lawrence Berkeley National Laboratory, data centres accounted for approximately 4.4% of US electricity consumption in 2023. Under high-growth scenarios, their share could rise to between 6.7 and 12% by the late 2020s ( US DOE, 2024 ) (see Figure 2 ). This reflects not only cloud computing needs but also AI clusters that require dense racks, liquid cooling systems, and uninterrupted operation. As hyperscale campuses reach capacities
multi-year delays. Markets such as Virginia, Texas, Ohio, and the Tennessee Valley experienced growing tension between rising load and constrained transmission corridors ( BloombergNEF, 2024 ). This surge in demand created a paradox at the heart of the energy transition. Renewable generation continued to accelerate, and solar remained the fastest-growing source of new capacity. Yet the speed and profile of demand growth also reinforced the ongoing role of natural gas as a flexible, dispatchable resource that could support variable renewables, provide grid stability, and meet load growth in regions where interconnection constraints limited new renewable additions. Solar and wind in a more constrained policy environment Despite policy uncertainty, solar and wind continued to expand across the US, though under more constrained conditions than in previous years. Solar remained the dominant source of new capacity additions, but rising module import tariffs, tighter domestic content rules, and higher interest rates increased project costs ( US EIA, 2024-2025e ). Smaller developers struggled to secure equipment and financing at levels consistent with earlier assumptions. Several projects were reduced in scale or reconfigured as storage-only installations to navigate shifting credit eligibility. Wind development softened more noticeably. Onshore wind faced growing site constraints, localised opposition, and interconnection barriers. Offshore wind encountered cost inflation, supply chain bottlenecks, and challenges aligning state procurement programmes with tightened federal
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Figure 2 Total US data centre electricity use from 2014 through 2028. Source: (US DOE, 2024)
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credit criteria ( US EIA, 2024-2025a ). The OBBBA revisions further complicated the landscape. Compressed qualification timelines forced developers to accelerate engineering and procurement schedules, often without clarity on final tax credit guidance. The narrower domestic content rules
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Figure 3 US added electricity-generating capacity. Source: (US EIA, 2025a)
added further pressure. Developers became more selective, focusing on projects with credible offtake, proximity to infrastructure, and clear compliance pathways. Blue hydrogen gained momentum in the Gulf Coast, where existing pipelines, CO2 storage resources, refineries, and petrochemical complexes created natural clusters for early deployment. Green hydrogen, on the other hand, contracted in many regions due to higher capital costs, slower renewable interconnection, and uncertainty around hourly matching requirements (BloombergNEF, 2025b) . One of the clearest signals of the sector’s recalibration came in November 2025, when ExxonMobil paused its Baytown blue hydrogen project ( Dang, 2025 ) ( Eclipse Energy, 2025 ). The company publicly attributed the decision to weak customer demand and difficulty securing long-term offtake commitments under prevailing market and policy conditions. The pause underscored the commercial challenges faced by large-scale blue hydrogen facilities, even in regions with strong industrial fundamentals. Alongside these shifts, subsurface hydrogen pathways began to gain attention as potential complements to conventional production. Companies such as Eclipse Energy advanced technology that stimulates hydrogen generation within depleted oil reservoirs by leveraging natural geochemical processes and existing well infrastructure (Eclipse Energy, 2025) (see Figure 4 ). This approach avoids the use of surface electrolysis and reduces the amount of new drilling required. It also positions engineered geologic or natural hydrogen as a potentially low- cost and low-carbon pathway that repurposes legacy assets while minimising surface footprint.
placed pressure on a manufacturing base that remains globally dependent, especially for nacelles, bearings, inverters, and certain power electronics. Transmission remained a structural bottleneck. While Federal Energy Regulatory Commission (FERC) Order 1920 created a framework for long-term regional planning and more consistent cost allocation, it did not materially accelerate near-term delivery of transmission projects already stuck in permitting reviews. Many renewable projects continued to face multi-year delays driven by environmental assessments, local opposition, and interconnection queue backlogs ( FERC, 2024 ). Yet meaningful capacity in renewables was still added. Corporate buyers maintained a strong interest in time-matched procurement solutions. Storage costs continued to decline, enabling a growing number of solar-plus-storage configurations. Meanwhile, long-duration storage technologies advanced through demonstration projects ( US DOE, 2025b ). Renewable growth persisted, but at a pace more aligned with practical constraints than with the expansive expectations of early IRA optimism. A more grounded hydrogen outlook Hydrogen entered 2025 in a recalibrated state. The years immediately following the IRA had seen bold targets, large-scale announcements, and high expectations for rapid deployment. But prolonged uncertainty around 45V guidance, particularly regarding temporal matching, deliverability, and additionality requirements, slowed momentum across much of the pipeline ( BloombergNEF, 2025b ). OBBBA’s shortened qualification windows
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Regulatory Comission’s (NRC) evolving Part 53 licensing framework introduces both anticipation and uncertainty for first-of-a-kind SMR designs ( US NRC, 2025 ). Even so, the broader narrative continues to shift in favour of nuclear, driven by increased demand for reliable, carbon-free capacity and the urgency of meeting around-the- clock electricity needs. Geothermal also advanced as enhanced geothermal systems demonstrated improved drilling success and reservoir performance. Techniques adapted from the oil and gas sector reduced well costs and improved subsurface productivity. Fervo Energy’s Cape Station project secured new financing and advanced toward commercial operation, reinforcing industry confidence that geothermal can scale into a meaningful source of firm, clean power (Fervo Energy, 2025) . While total US geothermal capacity remains small relative to other clean resources, 2025 marked a shift in perception: geothermal moved closer to being seen as a credible contributor to the firm-power portfolio needed for a more electrified economy. CCUS: A market in reassessment Carbon capture, utilisation, and storage (CCUS) entered 2025 with a large, announced pipeline but uneven project readiness. The US still had the highest volume of proposed capacity globally, yet only a modest share of projects advanced to final investment decision (FID) (Statista, 2024) (Global CCS institute, 2025) . OBBBA’s narrowed credit windows and tighter eligibility requirements forced many developers to revisit schedules, financing assumptions, and commercial structures. Permitting remained a major bottleneck. Louisiana entered 2025 already operating under Class VI primacy, and Texas continued advancing its application, yet long federal and state review timelines still slowed project progression ( US EPA, 2025 ) ( Trihydro Corporation, 2025 ). CO₂ transport infrastructure also trailed the pace of capture project announcements, creating additional constraints for early movers. As a result, meaningful momentum concentrated around industrial clusters along the US Gulf Coast, where storage formations, existing pipeline corridors, and dependable industrial offtake created the most viable near-term pathways for CCUS deployment. A notable development in 2025 was the
Eclipse Energy
Separation
Clean molecules
Injection system
Clean electrons
Figure 4 Eclipse Energy Black to Gold H2 process.
Source: (Eclipse Energy, 2025)
The rise of this category reflected growing interest in hydrogen options that can scale within existing industrial systems rather than rely solely on new production and transmission networks. Taken together, the US hydrogen sector in 2025 shifted away from the ambitious scale of early post-IRA announcements and toward more practical, infrastructure aligned opportunities. Developers concentrated on projects with clearer economics, stronger offtake, and more compatible siting conditions. This created a more measured but more durable foundation for future hydrogen growth. Nuclear and geothermal build momentum Nuclear energy gained renewed strategic relevance in 2025 as utilities, industrial buyers, and major hyperscalers sought firm, zero-carbon power with long-duration output. Interest in small modular reactors (SMRs) continued to grow, supported by federal tax credits and DOE loan programmes (US DOE, 2018 ) (X energy, 2024 ). Several hyperscalers advanced long-term strategies for securing firm, carbon-free power. Microsoft continued development of its fusion- based power purchase agreement with Helion (Helion, 2023) ( Nellis, 2025 ). Google deepened its work with utilities and research partners exploring next-generation nuclear technologies as part of its 24-7 carbon-free energy programme. Meta and other major cloud operators participated in regional utility planning efforts that evaluated SMRs as potential sources of clean, dispatchable power near emerging digital infrastructure hubs ( Constellation Energy, 2025 ). The nuclear supply chain continues to require significant expansion, and the Nuclear
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growing interest in natural gas generation paired with post-combustion carbon capture to serve large data centre loads. Developers, utilities, and infrastructure investors began evaluating CCUS-integrated gas projects as a way to provide firm, controllable power close to major digital campuses ( Global CCS Institute, 2025) . This was driven by the need for highly reliable local power that could operate continuously and respond instantly to the demands of high-performance compute. These projects also benefited from proximity to CO₂ storage resources and established pipeline corridors, which reduced transport costs and improved feasibility. While still in early stages, the concept gained momentum as load growth outpaced the speed at which new transmission, substations, and renewable interconnections could be built. For operators facing multi-year interconnection queues or limited grid headroom, CCUS-enabled gas emerged as a practical pathway to combine reliability with lower-carbon generation in areas experiencing rapid digital and industrial expansion. Direct air capture (DAC) continued to attract investment but stayed in the early commercial phase, with high capital costs limiting the number of projects moving toward construction (US DoE, 2025a) . In short, CCUS in 2025 displayed substantial long-term potential but was shaped by near-term pragmatism, with progress driven by smaller, more executable projects rather than the large hubs envisioned earlier in the decade. Role of natural gas in a high-demand decade Natural gas maintained a central role in the US energy system through 2025. Production levels remained near historic highs, driven primarily by associated gas from oil basins. Liquefied natural gas exports expanded, linking US supply more closely to international markets and reinforcing the country’s position as a major global energy supplier ( US EIA, 2024 ) ( US EIA, 2025b ). In the power sector, gas provided the flexibility needed to balance rising renewable penetration and growing data centre demand. Several utilities initiated or expanded simple- cycle turbine projects that could come online quickly to support local reliability needs ( US EIA, 2025c ). This underscores the stabilising role natural gas continues to play, supporting
Class VI permit status
Active: Final permit has been issued
Bubble size represents 2GW of power demand
Operational CO pipeline
renewable growth by providing firm capacity when transmission constraints or weather variability limit clean generation. Transition defined by discipline and durability The year 2025 saw the energy transition learning how to operate under real-world conditions. Markets, technologies, and policies all continued to move, but with a sharpened sense of what it takes to turn ambition into durable progress. Companies adapted their strategies, developers recalibrated project pipelines, and states and regions leaned into their comparative strengths. The actors who advanced most effectively were those who embraced complexity rather than resisted it. What emerged was a clearer picture of an energy transition that is broader and more resilient than any single policy cycle. The rise of digital load, the persistence of infrastructure bottlenecks, and the evolution of clean energy technologies all underscored the need for solutions that are both innovative and grounded. That blend of creativity and pragmatism is now shaping the investments and decisions that will define the next phase of US energy development. Figure 5 Announced and operating AI training and hyperscale data centres, CO2 transport, and storage by US power market. Source: (BloombergNEF, 2025a) BNEF Carbon Capture for Powering US Data Centers
Nishadi Davis Nishadi.Davis@woodplc.com VIEW REFERENCES
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AHEAD A long history of looking
For nearly a century, Grace catalysts have kept fuel and petrochemical feedstocks flowing from the industry’s largest refineries to the trucks, trains, planes, and ships that keep our world running. We are leveraging our long history of innovation in fluid catalytic cracking to develop products that enable lower carbon fuels and help meet the challenges of the energy transition.
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How advanced heat exchanger solutions can accelerate CCS When smartly integrated with plant utilities and designed holistically, heat exchanger technologies can enhance the scalability of CCS for net zero
Marcin Karas and Alexander Gernhardt Kelvion
T he carbon capture and storage (CCS) process using solvent-based absorption technologies is thermally demanding and energy-intensive. Therefore, minimising energy demand is crucial for reducing operating costs and ensuring the economic viability of CCS projects. Efficient heat integration is essential to minimising the energy demand associated with the process. This is where the right heat exchange solutions can make a big difference. Heat exchangers are at the heart of CCS performance. As critical components, they enable heat recovery, lean/rich solvent heat exchange, and reboiler operation. Additionally, they support waste heat utilisation from flue gases and keep sorbent at a temperature optimal for CO 2 transfer. This article explores the technical aspects, features, and challenges of heat exchangers for point-source absorption CCS systems. It
highlights how Kelvion’s energy-efficient heat exchanger solutions can significantly reduce energy demand and operating expenses. Kelvion covers the full CCS heat integration chain, with advanced solutions for flue gas heat recovery, highly efficient plate heat exchangers (PHE) for lean/rich heat exchange, and the K°Flex reboiler for solvent regeneration. It also offers air-cooled heat exchangers, dry coolers, and wet cooling towers for the ambient air-based process and central recooling. Point-source CCS systems Point-source-based CCS systems are recognised as a crucial element in lowering global CO 2 emissions and achieving net-zero targets, especially in hard-to-abate industries such as cement and steel plants. They can also be an add-on to gas or waste-to-energy power plants,
Central cooling system
Heat recovery & ue gas cooling
Solvent recovery system amine treating unit
CO compression
CO to compression
Flue gas Sweet gas
Re ex drum
Make - up water
Overhead condenser K o Flex
Lean solvent
Rich solvent
Direct contact cooler
Water
Air
Compressor c oolers / K o Bond / Double tube safety / AFC
Stripper tower/ regenerator
Absorber
CW
Economiser
Lean/rich PHE
Flue gas Sour gas
Steam Stripper reboiler K o Flex
Rekuluvo/ Rekugavo
K o Flex
Rich solvent
Figure 1 Simplified process scheme of an absorption-based point source CCS system
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As the process requires substantial heat input while maintaining a cold end (absorption) and a hot end (desorption), various heat exchangers are integrated into the process. Furthermore, often a central recooling system is needed to dissipate surplus heat from the process in water-based systems or in large air-cooled heat exchanger installations. Flue gas cooling and waste heat recovery The CO 2 absorption process within the absorption column requires a temperature level of around 40°C. Hot flue gas must be cooled before it enters the core process. This can be done in two ways. The first is via a direct contact cooler, which cools the flue gas by spraying water directly into the gas stream. The heated water is collected and recooled in an air-cooled heat exchanger or a PHE. The second option is to cool the flue gases via heat exchangers, enabling heat recovery for use in the CCS process or for other heating purposes. Kelvion provides tubular heat exchangers and welded PHEs for this purpose. They transfer the energy to secondary fluids, such as hot water, thermal oil, or combustion/drying air. There are many tubular heat exchanger designs, with various tube types, flow arrangements, and materials. Welded PHEs, such as Kelvion’s Rekugavo, are the perfect choice for gas-gas heat exchange in a countercurrent flow arrangement. They achieve high heat recovery efficiency, even with low temperature differences. Depending on the specific project, tubular and plate heat exchangers can be combined to integrate multiple heat exchangers for different purposes in a single overall solution (see Figure 2 ). Choosing the right technology for heat exchangers can be challenging, as each option offers unique features. For example, using tubular heat exchangers for gas-to-gas applications provides geometrical flexibility. When dealing with gas streams with significant volume flow differences, multiple passes can be used for one side of the unit. This allows for optimising the range of gas velocities and Reynolds number, leading to a good heat transfer coefficient. Plate technology offers other benefits, such as compactness, a large heat exchange surface, and counterflow efficiency, but it is the best choice for similar gas volume flows. Depending on the process and facility where
Tube heat exchanger
Tube heat exchanger
Plate heat exchanger
U-tube heat exchanger
Figure 2 Integrated heat exchanger solution
where CCS systems are installed to separate the CO 2 from the flue gases. Furthermore, point- source CCS systems can be integrated into enhanced gas and oil recovery facilities to store CO 2 in reservoirs, thereby lowering CO 2 emissions from fossil fuel usage. Flue gas absorption CCS system overview In a flue gas absorption CCS system (see Figure 1 ), such as those installed downstream from a waste- to-energy or cement plant, the flue gas must first be cooled. This can be realised by a direct contact cooler or the integration of heat exchangers. The flue gas then enters an absorption column, where it is brought into contact with a solvent, such as an amine solution, to absorb the CO 2 . The CO 2 -rich solvent is then sent to a stripper column, where the CO 2 is released, and the solvent is refreshed. By conducting this reciprocal absorption/desorption process, a continuous CO 2 capture process is realised. After the CO 2 gas leaves the stripper column, it is cooled, compressed, and transported to a storage or utilisation location.
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