LNG

Delfin Midstream is close to signing a contract with Samsung Heavy Industries for the supply of the second and third floating liquefied natural gas (FLNG) vessels for its Delfin LNG export project in Louisiana.

With LNG Canada and other projects advancing, Canada is entering a broader energy-infrastructure boom rather than a one-off build-out. For upstream companies like Canadian Natural Resources, that shift lifts realized gas pricing, strengthens margins, and expands long‑term cash‑flow potential.

Kinetics LNG has secured a $125 million investment from Turkish private equity firm Actera Group to help fund the expansion of its floating LNG business, targeting emerging markets.

Shell CEO Wael Sawan has expressed reluctance to spend the company’s own equity on US LNG projects, citing the availability of low-cost infrastructure funding. His remark signals a shift towards prioritising shareholder returns over equity commitment in an increasingly oversupplied global LNG market.

European countries’ reliance on US LNG imports comes with a risk, TotalEnergies’s CEO Patrick Pouyanne warns. Infrastructure constraints could limit how much LNG the US can actually deliver, while new US supply coming to market in late 2026 is largely uncontracted and could be shut-in if spot prices collapse.

Investments in North American natural gas infrastructure – notably LNG terminals – run the risk of becoming stranded assets after 2040 as accelerated decarbonisation reduces LNG demand in Europe, Asia Pacific and China, DNV warns.

Constraints on feeder pipelines could coke the imminent surge in US LNG exports. “It’s not about the availability of gas, it’s about transportation. “How are we actually going to get it there?,” Cheniere’s vice president Nishita Singh told a conference in Texas.

Sempra Infrastructure has resumed construction on the plant’s 13 mtpa Phase 1 foundations, after works were halted a fortnight ago due to a scaffolding collapse. Still, targeted FID on Porth Arthur LNG Phase 2 in the third quarter of 2025 remains in place.

Plans for Germany’s green hydrogen economy face serious delays due to uncertain future pricing and lagging infrastructure build-out, e.g. conversion of LNG import terminals and gas-fuelled power plants. Investment is slowly forthcoming: of the government’s targeted 10 GW new electrolyser capacity by 2030, only 1.6 GW has been instated so far.

“The hydrogen market is not scaling at the speed needed,” said Kerstin Andreae, chair of the German Association of Energy and Water Industries (BDEW) when presenting a new report co-authored by the consultancy EY.

“Investors and developers need clear rules, support for infrastructure, and reliable pricing signals to move forward,” she stressed. In fact, green hydrogen, produced by electrolysis using renewable electricity, made up just 0.5% of total hydrogen output in Germany in 2023 – while the vast majority is still made from fossil fuels, primarily natural gas.

The ‘Energy Transition Progress Monitor 2025’ warns that slow progress on key hydrogen infrastructure and weak investment conditions are stalling the ramp-up of green hydrogen. The report, published on Monday, cites a “significant investment hurdle” caused by regulatory uncertainty, infrastructure gaps, and market risks.

Industrial demand declines

Fossil-based generation of both hydrogen and electricity is becoming a new phenomenon amid weakening industrial demand, particularly in key sectors such as refining, ammonia, methanol, and chlorine production. Despite these setbacks Germany is on track to meet its 2030 climate targets, though analysts stressed shortfalls remain in the transport and heating sectors.

The incoming federal government faces “tremendous pressure” to deliver results, BDEW underlined. Key policy priorities include speeding up permitting for renewable projects, aligning grid expansion with energy demand, and designing a new electricity market framework that rewards flexibility and low-carbon solutions.

Industry groups, meanwhile, want the government to reinvigorate hydrogen efforts. BDEW and more than a dozen other trade associations called for a “restart” in bilateral energy ties aimed at forming a European hydrogen alliance. The groups called for an overhaul of EU rules on green and low-carbon hydrogen, the rapid buildout of cross-border hydrogen infrastructure, and harmonized certification standards across the bloc.

A close partnership with France, they argued, could “inject decisive momentum” into Europe’s hydrogen strategy. Signatories to the joint statement included BDEW, the chemical industry association VCI, the automotive group VDA, the local utility association VKU, and the European hydrogen lobby Hydrogen Europe.

Though Germany must phase out fossil gas by 2045 to become climate neutral, there is no clear roadmap for exiting natural gas in the power sector and the future role of LNG, the International Energy Agency (IEA) criticises. The German ‘LNG Acceleration Act,’ for once, stipulates an end of LNG imports by 2043 when terminals should be converted to hydrogen.

To meet that timeline, substantial investment in Germany’s traditional gas infrastructure would be required, analysts pointed out.

For repurposing LNG regas terminals to accommodate hydrogen, the key question is temperature. Methane liquefies at −160°C and hydrogen −253°C. The European Network of Transmission System Operators for Gas (ENTSOG) recommends terminal operators to carry out a risk assessment of LNG in order to analyse the impact on the process conditions, properties of mixtures and consequences.

As for storage, Germany has the largest gas storage capacity in the EU with around 40 gas storage facilities holding more than 24 bcm. Up to 1% hydrogen per volume can be blended into an average gas storage facility – while a pipeline that currently carries mainly natural gas can transport about three times as many cubic meters of hydrogen, an ENTSOG-G study finds.

Key gas pipelines in Germany include Nord Stream 1, which used to transport Russian gas through the Baltic Sea; the Yamal-Europe Pipeline, now primarily used to transport natural gas from Germany to Poland; the Trans Europa Naturgas Pipeline, connecting the German and Dutch gas grids; and the Europipe I and II pipelines, which import natural gas from Norway’s North Sea fields into Germany.

Clear timeframe needed for gas-to-H2 conversions

Looking at the power sector, there is currently no roadmap for exiting natural gas in the power sector. Unlike coal, no timeframe has been set out, though the target of 100% fossil-free generation by 2035 indicated the need for speedy gas-to-hydrogen conversions – or utilities face the risk of plant closures.

Uncertainty about tenders for hydrogen-ready power stations or a future capacity market is has made Germany’s largest utilities to withhold investment in new power stations, which, in turn, risks to push up wholesale power prices.

The IEA hence urges the incoming coalition government to clarify the timing of a future gas exit. Timeframes for mandated hydrogen conversions would provide industry with the certainty needed to invest in the required import infrastructure (for both natural gas and hydrogen) and industrial clusters.

Electrification in focus first, hydrogen and CCUS second

The industry in Germany is struggling to stay competitive in the face of rising fuel costs and high electricity prices. To mitigate the risk of deindustrialisation, IEA analysts recommend policymakers in Berlin should concentrate efforts on promoting energy efficiency and electrification” in the short run. The rising adoption of hydrogen and post-combustion carbon capture utilisation and storage (CCUS) are seen as e viable pathways in the longer term.

For now, Germany’s dependency on natural gas continues “without a clear end in sight,” analysts criticise the government’s failure to set out clear policies on how to enact the clean energy transition. The outgoing government’s Power Plant Strategy attempted to tender 12.5 GW of new natural gas-fired power plant capacity that could later run on hydrogen.

“In this way, the construction of new hydrogen-ready gas-fired capacity could avoid a fossil fuel lock-in that is not at odds with the electricity generation target, as long as the fuel switch takes place on time,” analysts acknowledged but called for more clarity around the viability of hydrogen-ready gas plants.

Gas peaking plants are believed to keep playing a vital role in grid balancing beyond 2035. But other flexibility options, notably industrial demand response, storage and interconnections, should be encouraged as these “may displace the need for additional generation capacity,” analysts argue. The IEA hence urges the German government to “move ahead with the future electricity market design proposals, including a capacity mechanism.”