“Let Green Gas Count” calls for clarity on the role of market instruments for renewable gaseous fuels in the Greenhouse Gas (GHG) Protocol. To fully unlock the potential of low-carbon green gas solutions, the Protocol must evolve to reflect the role of robust market instruments, as the guidance that previously provided a necessary investment certainty on the renewable gas market has been withdrawn.

IGU’s Director for Strategy and Advocacy, Mark McCrory, commented on IGU’s decision of co-signing this Open Letter that “the global gas industry is already rising to the decarbonisation challenge, innovating and collaborating to develop lower-carbon technologies – including renewable gaseous fuels. Creating the right market signals for investors will be critical in deploying these technologies at scale. The IGU therefore believes that the GHG Protocol must fully recognise established market-based instruments such as renewable gas certificates to provide clarity to investors and drive the decarbonisation of industry and corporates.”

Consequently, IGU is asking the GHG Protocol to:

1) Adopt a market-based approach for renewable gases in Scope 1 Inventory, for both fuel and feedstock applications. This approach could be part of the dual-reporting structure which includes both the location-based and market-based approach.

2) Issue an Interim Statement in the first half of 2025 confirming that robust market instruments will be recognised in GHG inventories, offering clarity and confidence for stakeholders as final standards are being developed.

What seems a simple commercial commitment, however, involves a web of complexities. Many EU utilities are not keen to buy (US) LNG on a long-term basis on the back of expected declining EU LNG demand in the long term. Also, European companies with US LNG contracts can redirect volumes outside Europe, especially international companies looking for profits. Finally, if the EU were to double its US LNG imports in line with the US doubling its LNG exports by 2030, that would dramatically increase the region’s dependency on one supplier, which the EU is not likely eager to do. 

EU Imports of US LNG in 2025

In 2024, EU imports of US LNG dropped to 51 billion cubic meters (bcm), from 62 bcm in 2023. Lower EU LNG imports was due to a mix of high storage levels in 2024, strong pipeline imports and flat EU gas demand, as well as a diversion of US LNG to more lucrative Asian LNG markets. Still, the two regions are deeply interconnected: the US supplied 45 percent of EU LNG imports in 2024 (114 bcm), while the EU purchased 43 percent of US LNG exports (119 bcm).

Higher EU imports of US LNG are likely to materialize in 2025 for two market-driven reasons, which have nothing to do with policies or politics:

• US LNG exports are bound to increase, as two new liquefaction plants start in 2025 (Plaquemines and Corpus Christi Stage 3). The EIA expects US LNG exports to increase by 17 percent in 2025.
• The EU will need to import more LNG to compensate for the halt on January 1, 2025, of Russian gas transit through Ukraine (which was around 15 bcm in 2024), and to refill EU storage facilities, whose levels were 20 bcm lower year-on-year as of mid-February 2025. 

However, flexible US LNG will effectively land in EU countries only if EU spot prices are high enough to divert it from Asian markets, which has been the case in early 2025 so far (Figure 1) due to very high European gas prices. Retaliatory Chinese tariffs on US LNG could also lead Chinese companies to redirect contracted cargoes to Europe.

Long-Term Contracts for US LNG

In January 2025, President Trump reversed one of the most debated decisions of the Biden administration: the pause on approvals of new US LNG exports to non-free-trade-agreement countries. Liquefaction plants are large, capital-intensive projects and need long-term contracts to secure financing and take final investment decision (FID).

A relatively low number of EU buyers signed long-term contracts with US LNG exporters after Russia invaded Ukraine in 2022, even though EU countries faced a 115 bcm/y drop in Russian pipeline gas between 2021 and 2023. Around 23 bcm/y of contracts were signed with US LNG projects now under construction: 55 percent with European utilities and the rest with European-based international oil companies (IOCs). Another 12 bcm/y were signed with projects still expecting to take FID, such as Calcasieu Pass 2, Sabine Pass Expansion, Lake Charles, and Cameron Phase 2. (See Table 1.) 

Trump could potentially fulfil the role of “LNG Marketer in Chief” to nudge EU companies to sign more US LNG contracts. But in doing so, will he transact with EU governments—which are rarely shareholders of gas companies (with a few exceptions such as Engie and Uniper)—or with EU companies directly? 

While the EC’s president pledged to buy more US LNG, the EC does not have any legal entity allowed to buy LNG on behalf of European countries, though the EC seems to be considering a more direct involvement in LNG projects to secure LNG and stabilize gas prices. Meanwhile, European utilities—as commercial entities—may not be so keen to bow to political whims and contract US LNG, or any LNG for that matter. They have witnessed a significant drop in EU gas consumption, face an uncertain outlook for EU LNG imports, cannot have long-term contracts for unabated gas going beyond 2049, and, as importers, will be exposed to methane emissions rules that are unlikely to be the priority of Trump’s administration.

Finally, it is questionable whether European-based IOCs would qualify as “European,” as far as any negotiations around the trade deficit are concerned, given the global nature of their LNG business, but Trump may see them as European. 

Implications for the Trade Deficit

A key reason for Trump’s ire against Europeans and desire to sell them more LNG is the US-EU trade deficit ($236 billion in 2024).

In 2024, US LNG exports to the EU were around $13 billion, according to the US Census Bureau (Figure 2), around 5.4 percent of the trade deficit. Trade data on US LNG exports observed by the US administration is influenced by both volume and price. US LNG exports price data is not straightforward: it could be the contract price (Henry Hub times a multiplier plus a liquefaction fee), or another price if the LNG is sold within a US company’s portfolio. Still, the implied annual LNG price is reasonably close to a reference contract price (115% Henry Hub + $3/mmBtu), despite a gap emerging over the past two years implying a higher sales price. 

Additionally, US and EU bilateral trade data are massively different, even accounting for currency differences. Indeed, the EU import price of US LNG is different from the US LNG export price—it can be a European spot price or the contract price plus the prevailing transport fee. Given the current high European spot prices, EU trade data are much higher than what the US reports (Figure 2). EU numbers equate to almost 8 percent of the deficit, and EU policy makers could use these trade data in the upcoming negotiation.

It’s the Economy, Stupid!

Whatever Trump may think he is gaining in the short-term by pushing more US LNG exports to EU countries, it will hardly be a sustainable solution to bridging the US-EU trade deficit. 

First, European LNG imports, including from the US, are likely to eventually dwindle as European gas demand decreases. While US LNG exports are bound to at least double by 2030, an increasing share of that is likely to go to the growing Asian market. 

Second, EU countries value LNG because of the diversity in suppliers. Increasing imports and moving to an 80–90 percent share of US LNG in total LNG imports would undermine this benefit of diversification from a security of supply perspective. 

Third, even if US LNG is contracted by a European company, it could end up elsewhere and not be counted in US-EU trade data. The beauty of US LNG is its destination flexibility. Offtakers can arbitrage between destinations depending on prices. European utilities are likely to deliver contracted LNG to their home market, but a European company like SEFE, with ambitions to build an international portfolio, could eventually send its contracted LNG to Asia. Meanwhile, aggregators such as Shell and TotalEnergies are beholden to their shareholders, not to ensuring Europe’s security of supply.

Finally, US-EU LNG trade also depends on the domestic US gas price. Trump’s pledge to decrease domestic energy (including gas) prices could be counter-productive to his desire to bridge the deficit. Meanwhile, higher domestic gas prices could help to reduce the deficit but hamper US gas consumers. 

Originally published by Columbia | SIPA.

The statements, opinions and data contained in the content published in Gas Expert Insights are solely those of the individual authors and contributors and not of the publisher and the editor(s) of Natural Gas World.

Since 2012, several different studies have been commissioned by the U.S. Department of Energy (DOE) since 2012 to support efforts to make a public interest determination regarding U.S. LNG exports. As noted in a 2023 Baker Institute study, each of these DOE-commissioned studies found a net gain from trade across a wide range of different scenarios considered and concluded the net benefits increase with resource availability. While often framed in the context of a larger resource base with more elastic cost-of-supply, these findings also indicate that any impediments to the development of infrastructure will reduce net gains to the U.S. from trade. 

In general, it appears that all the DOE-commissioned studies conducted prior to 2024 use an elasticity of supply that is too small. In other words, at a given price, actual U.S. production has exceeded what was anticipated even in the high domestic resource cases. It follows directly that the supply response of the modeling exercises is increasing over time.

• The National Economics Research Associates (NERA) 2012 study had the steepest, or least elastic, supply curves.
  
• The Baker Institute for Public Policy Center for Energy Studies (CES) and Oxford Economic 2015 study’s supply curves were flatter.
  
• The NERA 2018 supply curves were even flatter.
  
• The recently released DOE 2024 study prepared by OnLocation, Inc. with Industrial Economics, Incorporated, National Energy Technology Laboratory, and Pacific Northwest National Laboratory appears to have the most aggressive assumption about elasticity of supply.
  

That stated, all DOE-commissioned studies are long-run studies. Hence, they do not capture short-term variations in demand and the resulting impacts on price. This is what the models were built to do. The studies are constructed to examine the long-term, structural impacts of increased LNG exports. Any short-term model should recognize the difference between short-run and long-run elasticity. In the short run, prices tend to be more volatile due to the realization of capacity constraints that are not present in the long run. In fact, a long-run constraint would signal an investment opportunity that, when captured, would alleviate the constraint. This is a subtle but important point in the policy context.

Any forward-looking study should recognize the role that associated gas production is playing in U.S. market balance. Associated gas is an inframarginal source of supply that stretches the supply curve, which helps prevent prices from rising when demand or exports increase. It also connects the gas supply situation in the U.S. directly to oil-directed upstream developments, which is another very important point in the policy context.

Any future study will likely be hard-pressed to not find positive net macroeconomic benefits from trade. Not only is this a basic outcome of international trade theory, but it also follows directly from previous work, which all found net positive benefits. In this context, if a trade is “in the money” (ITM) in a competitive equilibrium, then value must matriculate to all actors along the supply chain, lest the investments necessary to support supply chain development will not occur. Moreover, the value must be higher than alternative uses of investment capital because capital will seek the highest returns. This is why previous studies find net positive macroeconomic benefits associated with exports, despite underestimating domestic supply at a given price.

It directly follows that a license to export LNG is not a guarantee that exports will occur. Rather, a license is an option that the holder can choose to exercise if the export opportunity is ITM. In other words, an export project that is unable to earn a sufficient return on investment along the full supply chain will not move forward, leaving the option unexercised. This has already been witnessed at scale in the history of U.S. LNG trade; for instance, in the early 2000s, over 45 LNG import terminals received a license to import LNG, but those options were not exercised because market conditions did not support it.

There is now attention being given to examine the environmental implications of U.S. LNG exports, both domestic and abroad, as part of the public interest. This is inherently difficult to model, and the outcome can be entirely dependent on assumptions made about sources of supply and destination markets. Domestic environmental impact analyses have been conducted to examine pathways for emissions reductions. However, the sources of supply and pathway from wellhead to liquefaction are not necessarily the same across different existing and proposed export terminal. As such, no macro-level analysis emissions will suffice. Each terminal should be evaluated independently.

International environmental impacts are complicated by the fact that U.S. LNG export cargoes are very flexible. U.S. LNG is loaded free on board (FOB), so predicting where it will land is akin to predicting relative international price movements. U.S. LNG can be, and has been, redirected to chase the highest price. As such, cargo destinations can be influenced by a variety of factors that carry different implications, including:

• Seasonal demand fluctuations.
• Regional deliverability constraints and storage movements.
• Geopolitical disruptions.
• Weather-induced disruptions, among others.

Beyond cargo destination, predicting the fuel mix in different regions is also difficult. A probability weighted approach could be used to estimate how and when gas may compete in different regions, but the uncertainty is inescapable. Moreover, the role of policy in shaping the competitive landscape for different fuels is highly variable from region to region. Any approach that ignores this uncertainty is likely flawed from the outset.

It is important to note that estimating environmental impact is distinctly different from estimating potential gains from trade. All that is required to assess gains from trade is sufficient international demand to incentivize export flow, regardless of where it lands. While there is uncertainty therein, the uncertainty is amplified when trying to estimate environmental impacts because information about specific markets and the energy mix therein — now and in the future — is also required.

Finally, if the path forward is to expand the scope of a public interest determination, then the energy security dimensions of U.S. LNG exports should be incorporated. The recent experience in Europe following the Russian invasion of Ukraine and disruption of supply is a very recent, very salient example of why this is so. U.S. LNG demonstrated significant flexibility in responding to the market signals in Europe, helping to mitigate the economic damage that Russia’s actions inflicted. If these events transpired in 2015, or any year prior to U.S. LNG exports commencing, it would have likely produced a very different outcome. In short, U.S. LNG is a credible threat deterrent to hegemonic intent with energy resources and trade. 

Read full report by Baker Institute.

The statements, opinions and data contained in the content published in Gas Expert Insights are solely those of the individual authors and contributors and not of the publisher and the editor(s) of Natural Gas World.

Meanwhile, in the U.S., President Trump’s administration has promised to “unleash American energy dominance” by lifting restrictions on new permits for LNG exports. But questions remain about domestic gas production capacity, infrastructure constraints, and the impact on U.S. prices.

How are these developments reshaping global gas markets, and what do they mean for Europe’s industrial competitiveness? How might geopolitical tensions affect the future of global gas trade? And what does all of this mean for reducing greenhouse gas emissions?

This week on the show, Jason Bordoff talks with gas market experts Anne-Sophie Corbeau and Ira Joseph about the outlook for LNG and its geopolitical and environmental implications.

Anne-Sophie is a global research scholar at the Center on Global Energy Policy, where she focuses on hydrogen and natural gas. Her career in the energy industry spans over 20 years, including stints as the head of gas analysis at BP, senior gas analyst at the International Energy Agency, and research fellow at the King Abdullah Petroleum Studies and Research Center. 

Ira is a senior research associate at the Center on Global Energy Policy. Previously, he headed global generating fuels and electric power pricing at S&P Global Platts. Before that, he was the global head of gas and power analytics at Platts.

Listen to podcast by Center on Global Energy Policy at Columbia University.

The statements, opinions and data contained in the content published in Gas Expert Insights are solely those of the individual authors and contributors and not of the publisher and the editor(s) of Natural Gas World.

The benchmark front-month contract at the Dutch TTF hub was down 1.30 euros at 49.75 euros per megawatt hour (MWh), or $15.28/mmBtu, by 0913 GMT, LSEG data showed.

The contract fell earlier to 49.25 euros/MWh, the lowest level since January 29.

"The weather forecasts now agree that milder and windier conditions are on the way (probably by the middle of next week)," Energi Danmark analysts wrote.

The British weekend contract TRGBNBPWE was down 4 pence at 125 pence per therm while the Dutch day-ahead contract TRNLTTFD1 shed 1.58 euros to 50.25 euros/MWh.

The British energy company has created three different scenarios for modelling energy security in the long term but added that they do not reflect its strategy or business plan.

The most positive outlook in terms of economic growth is dubbed 'Surge' and presupposes a pervasive use of artificial intelligence that would boost productivity globally and drive up the energy demand. 

A second scenario called 'Archipelagos' sees countries around the world focused more on their self-interest than working together to spread the use of AI and develop renewable energy sources.

The 'Horizon' scenario is instead based on the assumption that the world will reach net-zero CO₂ emissions by 2050 and deliver a global average temperature rise below 1.5 degrees Celsius by the end of the century.

"In all three scenarios, liquefied natural gas shows significant growth in the near term, fuelled by ongoing projects in Qatar and the United States, reaching around 550 million tonnes per year (MTPA) by the end of the decade," Shell said in its report.

After 2030, the expectations on LNG diverge significantly in the three different scenarios, with supply for the super-chilled gas continuing to grow and reaching 700 MTPA beyond 2040 in the 'Surge' scenario. In the 'Horizon' scenario, LNG demand is seen peaking in the early 2030s. 

Natural gas is seen growing until 2045 in the most upbeat scenario, 'Surge', while it is projected to peak in the very near term in the 'Horizon' scenario in order to meet net zero emissions by 2050.

Finally, Shell cites the electrification of road transport as the main reason for the world reaching peak oil demand in 2030 at the latest in the 'Surge' scenario.

In all the three scenarios Shell sees an upward pressure on energy demand.

"The scenarios highlight that primary energy demand in 2050 could be nearly a quarter higher than 2024 depending on economic growth rates, energy efficiency gains and the pace of electrification," the report said.

The group is expected to release its outlook focused on LNG later this year.

(Reporting by Francesca Landini and Alessandro Parodi, Editing by Louise Heavens)

The European Commission is preparing a package of measures, due to be proposed on February 26, to improve industries' competitive edge and help bring down energy prices.

Benchmark European gas prices rose this week to a two-year high of 58 euros per megawatt hour (MWh), boosted by cold weather and depleting gas storage tanks. That has added to concerns about the higher energy prices European firms face, compared with competitors in the U.S. and China.

Industry participants are worried that this could prompt Brussels to revive the idea of capping gas prices, weeks after a previous EU gas price cap introduced during the 2022 energy crisis expired after never once being triggered.

"We believe this measure, if announced, could have far-reaching negative consequences for the stability of European energy markets and the security of supply across the continent," the industry groups said in a letter to Commission President Ursula von der Leyen.

A cap would "harm the trust" in the EU's benchmark gas price, prompt market participants to switch to use other reference gas prices outside the EU, and make it harder for Europe to attract liquefied natural gas cargoes in price-competitive global markets, the letter said.

Its signatories included industry associations Eurogas, Energy Traders Europe, the association of energy exchanges Europex, and financial markets association AFME.

The Financial Times reported on Wednesday the Commission is considering a gas price cap as part of this month's package of support for industry, citing people with knowledge of the talks.

A senior EU official told Reuters on Wednesday the idea was not being considered.

The EU's previous gas price cap had also been opposed by industry and by national governments, including Germany and the Netherlands, who warned it would hamper Europe's ability to secure fuel supplies.

The cap was designed to kick in if European gas prices hit 180 euros per megawatt hour. It was never triggered, as the benchmark EU gas price has not reached that level since Europe's energy crisis in 2022, after Moscow slashed gas deliveries to the region.

(Reporting by Kate AbnettEditing by Bernadette Baum)

Equinor and Shell are joint operators of the country's mega gas project, while ExxonMobil, Pavilion Energy, Medco Energi and Tanzania's national oil company TPDC are partners.

The development has been stalled by proposed government changes to a financial agreement reached in 2023.

"The project hasn’t stopped, we are negotiating on the terms of how we can make the project viable for both of us," Biteko told Reuters at the India Energy Week conference.

He added that some government incentives would have to be given, and that the production volume depends on negotiations.

"Can't say when until we complete the negotiations, but I think the negotiations will be complete within this financial year, between now and June," Biteko said.

The project would unlock 47.13 trillion cubic feet of natural gas deposits in the country.

Tanzania also plans to launch an exploration licensing round for 26 oil and gas blocks on March 5, Biteko said.

Together with France's TotalEnergies and China's CNOOC, Uganda and Tanzania are also developing a 1,445-kilometre-long pipeline to transport Ugandan crude oil to Tanzania's Indian Ocean coast.

Biteko said construction is progressing well, with the pipeline 47% complete.

"Likely in 36 months we will realize the completion," he added.

(Reporting by Nidhi Verma, Shariq Khan; Writing by Florence Tan; Editing by Jan Harvey)

Senior government officials from Turkmenistan, representing oil and gas, energy, construction, transportation, information technologies, telecommunications, industry, agriculture, and textiles, will take the opportunity to present and discuss the nation’s most recent and promising investment prospects. The Forum is poised to be an essential platform to showcase the diverse opportunities available across these strategic sectors of Turkmenistan’s economy. 

Additionally, the Forum will bring together a distinguished lineup of international figures, including senior officials from major international organisations and financial institutions, such as OPEC, UNECE, the Global Gas Center, and the International Energy Agency, IRENA, the World Bank, the Asian Development Bank, the European Bank for Reconstruction and Development, BNP Paribas, and the UK Export Finance Agency (UKEF), alongside highly regarded experts and top executives from leading energy companies such as Petronas, Total Energies, and CNPC ExxonMobil, ADNOC, Dragon Oil, and ENI. These top experts will offer valuable insights, exchange knowledge, and provide in-depth analysis of Turkmenistan's current and future investment climate and beyond. 

Building upon the success of the previous TEIF 2024 held in Paris, which facilitated significant agreements to attract investments in Turkmenistan's energy sector, the organizers of the upcoming event are confident that TEIF 2025 in Kuala Lumpur will encourage further investment from the Southeast Asian countries.

As global energy transition efforts gain momentum, Turkmenistan is positioning itself to adapt and leverage its vast potential. From possessing the world's largest onshore gas field, “Galkynysh”, to offering optimal conditions for renewable energy development, Turkmenistan offers extensive investment opportunities to all interested parties. The forthcoming Forum in Kuala Lumpur will serve as a pivotal platform where major national and private companies will seek foreign direct investment across the crucial sectors of Turkmenistan’s growing energy, industrial, transportation, agricultural, and many other spheres of the economy.  

TEIF 2025 will feature comprehensive discussions that will delve into key topics such as the development of offshore hydrocarbon resources in the Turkmen sector of the Caspian Sea, the innovative application of cutting-edge technologies to enhance production from mature fields, subsequent phases of development of the  “Galkynysh” gas field, the progress and implementation of the Turkmenistan-Afghanistan-Pakistan-India (TAPI) gas pipeline project, the construction of advanced gas chemical facilities and the concerted efforts to reduce methane and associated gas emissions, contributing to a more sustainable energy future.

Driven by the motto Invest in a Stable, Prosperous, Dynamic Economy, the Forum’s agenda will encompass insightful discussions on the following agenda:

• 2025 – International Year of Peace and Trust: Turkmenistan's Role in The Future of Global Energy and Sustainable Growth.

• New Investment Opportunities in Turkmenistan's Energy Sector: Natural Gas and Monetisation

• Accelerating The Process of Attracting Investments into Infrastructure Projects in Turkmenistan with A Focus On Construction, Transport, Information Technology and Telecommunications

• Investment Opportunities in The Turkmenistan's Energy Sector: Oil and Petrochemicals

• Development of Manufacturing and Increase In Exports Of Industrial, Agricultural, Textile And Food Products

• Strategies Based On the United Nations SDGs: Reduction of Methane and Co2 Emissions and Promoting Innovation in Clean Energy

Business meetings with senior executives from Turkmenistan’s major economic sectors will provide invaluable insights into the country’s new investment opportunities.

TEIF 2025 will unlock new opportunities, foster innovation, and drive sustainable growth, ensuring a brighter and more prosperous future for Turkmenistan and its global partners.

For further details, please visit the official event website at https://teif-turkmenistan.com/en or contact us via email at info@tef-turkmenistan.com.

Follow us on social media for the latest news and updates: 

Instagram: tef_turkmenistan

Linkedin: Turkmen Energy Forum

"Naftogaz Group's production facilities in Poltava region were damaged. Fortunately, there were no casualties," the company said in a statement.

Naftogaz "is taking all necessary measures to stabilise the gas supply situation in the Poltava region", it added.

The Ukrainian air force said Russia had launched a combined attack, using 19 cruise, ballistic and guided missiles against gas production facilities in the Poltava region.

No missiles were reported shot down.

Poltava's regional military administration said that nine settlements in the Myrhorod district had been left without gas.

Russia, which previously focused its missile and drone attacks on the Ukrainian electricity sector, has in recent months sharply stepped up its attacks on Ukrainian gas storage facilities and production fields.

Ukraine's underground gas storage facilities are located in the west, while the main production capacity is in the east, in the frontline Kharkiv region, as well as in the Poltava region.

The state-run operator of the gas transmission system said Ukraine would likely increase natural gas imports to more than 16.7 million cubic metres (mcm) on Tuesday from 16.3 mcm on Monday.

Ukraine consumes 110-140 mcm of gas a day in winter and consumption is covered almost equally by gas production and reserves from storage facilities.

However, the former head of Ukrainian gas transmission system said that reserves in storage were close to critically low and this significantly reduced the ability to extract enough gas for daily consumption.

Both the drop in gas production and difficulties with extraction from emptied underground storage facilities may force Kyiv to increase the volume of imports.

The operator data suggested Ukraine would import 7.6 mcm of gas from Hungary, 7.3 mcm from Slovakia and 1.8 mcm from Poland.

(Reporting by Lidia Kelly in Melbourne, Pavel Polityuk and Anastasiia Malenko in Kyiv; Editing by Tom Hogue, Michael Perry, Louise Heavens and Kevin Liffey)

“Numerous factors collectively make the LNG-to-power sector an appealing investment opportunity in Southeast Asia, promising both economic returns investors and government alignment with broader environmental and energy security goals,” Pedersen said.

Rapid economic growth and urbanisation in Southeast Asia are driving a substantial increase in energy consumption, necessitating new and reliable sources of power. In the Philippines, market trends show that energy demand has been growing at an annual rate of approximately 4-5% over the past few years, she said. In 2023, the Philippines' electricity consumption was estimated to be around 110 terawatt-hours (TWh), up from about 100 TWh in 2020.  The Department of Energy of the Philippines projects that electricity demand could reach 150 TWh by 2030, driven by continued economic and population growth.

Energy diversification is another factor driving the demand. Countries in the region are seeking to
diversify their energy mix to enhance energy security and reduce dependence on coal and oil. LNG offers a cleaner alternative to those fuels but at potentially lesser capital costs then development of wholly new renewable energy systems.

Energy transition is another factor. Many countries in the region have set ambitious targets for transitioning to cleaner energy sources as part of their climate change commitments under international agreements like the Paris Agreement. LNG is a cleaner-burning fuel compared to coal and oil, producing lower emissions of carbon dioxide, sulphur dioxide, and particulates.

Several Southeast Asian governments are implementing policies and incentives to attract investment in LNG infrastructure and power generation, including favourable regulatory frameworks and tax incentives.  Vietnam's Power Development Plan VIII (PDP VIII), approved in 2021, emphasizes the role of LNG in the country's energy mix. The plan includes significant investments in LNG infrastructure, such as import terminals and LNG-to-power projects, to diversify energy sources and reduce reliance
on coal.

Advances in LNG technology, including more efficient and cost-effective liquefaction, transportation, and regasification processes, are making LNG projects more attractive and viable both globally and in the region, Pedersen said.

“The global LNG market has seen increased supply and competitive pricing, making LNG a more attractive option for power generation in Southeast Asia,” she added.

Infrastructure development and challenges

Southeast Asian nations are actively developing infrastructure to support the LNG-to-power sector; however, while the speed of development varies by country, the pace of development in the region overall needs to be accelerated to meet the burgeoning energy demand.

Vietnam has several LNG import terminals and power plants in various stages of planning and development, such as the Thi Vai LNG terminal and the Bac Lieu LNG-to-power project. However, regulatory hurdles and financing issues can slow progress, but the government is committed to expanding LNG infrastructure, Pedersen said. Based on industry assessments, the country's power consumption is forecast to rise by 11-14% next year.  In the short-term, the government is therefore turning to coal power plants to operate at high levels, as current LNG infrastructure is not sufficient to meet the demand.

Thailand has established LNG import terminals, such as the Map Ta Phut terminal, and is reportedly expanding its capacity with new projects, Pedersen said. While development is relatively advanced, ensuring sufficient supply and integrating LNG into the power grid remain priorities.

Indonesia is developing LNG infrastructure to support domestic power generation, including floating storage regasification units (FSRUs) and onshore terminals. However, geographic dispersion across the Indonesian archipelago makes comprehensive energy provision complex, and regulatory
complexities can slow the speed of development.

Malaysia, already a major LNG exporter, is enhancing its domestic LNG infrastructure to support power generation, including expanding existing facilities. RGTSU, a Malaysian LNG regasification
terminal, has publicly stated in various media reports that it has the capability to meet future demand. “The country is relatively well-positioned, but ensuring adequate domestic supply amidst export commitments is crucial,” Pedersen said.

The Philippines is progressing with several LNG import terminal projects, such as the Batangas Bay LNG terminal which received its inaugural shipment in 2023, to support its power sector. As of 2024, market reports indicate that the Philippines has the lowest power generation per capita in ASEAN, and electricity demand is growing faster than generating capacity. Whether the speed of Philippine LNG developments can meet the country's energy needs is yet to be seen.

Although, the potential is immense, the region faces some common challenges. Insufficient existing infrastructure for LNG import terminals, regasification facilities, and pipelines can hinder the growth of the sector. 

Another challenge is that of high capital costs, she said. High capital costs and the need for significant investment can be a barrier, especially in countries with less developed financial markets.

Inconsistent or unclear regulatory frameworks and policies can create uncertainty for investors
and developers.  Changes in governing administrations, such as the incoming Subianto administration in Indonesia, can result in shifting regulatory landscapes.

Fluctuating demand for power and competition from other energy sources, such as coal and renewables, can impact the viability of LNG projects, Pedersen said.

Finally, addressing environmental impacts and meeting sustainability goals can be challenging, particularly with increasing pressure on governments to reduce carbon emissions in accordance with their international and domestic commitments.

A mix of public and private investors

Given the extensive financing needs in Southeast Asia and the narrow budgets of local governments, the investors in the region are comprised of a diverse mix of public and private entities both domestic and international. These stakeholders often work closely together - this is why PPP is a popular mechanism for infrastructure development in the region.

Private sector investors include (i) major international oil companies active in LNG supply and infrastructure development (such as Shell, ExxonMobil, TotalEnergies, and Chevron), (ii) regional energy companies pursuing LNG import and power generation projects (such as PetroVietnam, PTT (Thailand), Pertamina (Indonesia), and First Gen Corporation), and (iii) private equity and infrastructure funds looking to invest in such projects (such as Global Infrastructure Partners (GIP), Macquarie Infrastructure and Real Assets (MIRA), and Blackrock). Public sector investors include (i) government-owned enterprises investing in LNG to meet domestic energy demand (such as Electricity of Vietnam, PLN (Indonesia), and EGAT (Thailand), (ii) sovereign wealth funds, supporting infrastructure development (such as Temasek Holdings (Singapore) and Khanzanah Nasional (Malaysia)), and (iii) multilateral development banks, providing financing and technical assistance (such as the Asian Development Bank, World Bank, and International Finance
Corporation).

Chinese and Japanese companies are particularly active in Southeast Asia.  The Batangas Bay LNG terminal in the Philippines, for example, has attracted foreign investments from Tokyo Gas and Mitsui, both of which are providing financial investment and technical collaboration to
ensure the project's success.

LNG imports

Talking about the extent of LNG import growth that the region will see, Pedersen said that industry analysts and reports from organisations such as the International Energy Agency (IEA) and the International Gas Union (IGU) suggest that LNG imports in Southeast Asia could grow by approximately 10-15% annually in the near term, driven by the expansion of the LNG-to-power sector. 

In terms of volume, this could translate to an increase of several million tons per annum (MTPA) of LNG imports across the region.  Globally, the largest change in imports in 2023 came from Asia with an increase of 10.50mn tonnes year/year, as lower prices by the end of the year incentivized spot imports by several markets in the region. Southeast Asia's LNG imports could rise from around 20-25mn tonnes/year to 30-35mn tonnes/yr over the next few years, she said.

“The extent of this growth depends, among other things, on the pace of local LNG terminal and power plant construction, supportive government policies and regulatory frameworks, and global LNG supply and pricing trends,” she added.

Role of renewables

Given the current position of Southeast Asia nations - with growing populations, rapidly increasing demand for energy, and limited energy infrastructure - LNG will serve an important role as a transition fuel as these nations develop their energy infrastructure for the future.  In the short-term, LNG, which is generally less capital intensive at present, will help balance intermittent renewable energy. 

A number of large-scale LNG infrastructure projects, including regasification facilities and import terminals, have recently been completed or will be completed soon across the region.  The long-term prospects of the LNG to power sector in Southeast Asia, however, may ultimately be constrained
by the rapid advancement and adoption of renewable energy.  Southeast Asian governments are already beginning to implement policies and incentives to promote renewable energy, shifting investment away from LNG.  Large numbers of renewable projects, including solar, wind, geothermal, etc., are currently being constructed or are in the pipeline for development.  The decreasing costs of renewable energy technologies deployed in the region will make them increasingly competitive with LNG, especially as improvements in energy storage and grid management technologies make it easier to integrate intermittent renewable energy sources into the power grid.  Expanded reliance on renewables will also help jurisdictions with dwindling oil and gas assets, like the Philippines, enhance energy security by reducing dependence on imported fuels.

Prime Minister Dorin Recean was taking part in a public online discussion nearly a week after gas reached Transdniestria's 350,000 residents for the first time in a month thanks to a 30 million euro ($31.2 million) grant from the European Union.

The emergency gas supply extends only to February 10, when a new arrangement must take effect to ensure gas is purchased and delivered to the pro-Russian region.

Recean restated the conditions set down by the EU this week for a proposed further 60 million euro grant - mainly evidence of an improved human rights record in the region and increases in prices charged for heavily subsidised power, water and heat.

The region's leaders have made no comment on the conditions.

Recean said he saw two scenarios unfolding.

"The first is they go on to the next stage of EU assistance and for that they need to fulfil the conditions," he said.

"If they don't agree, they have to find a solution on their own. Unfortunately, there is a third scenario under which people are again left without power in the cold and without water."

ROLLING BLACKOUTS

The region's residents suffered daily rolling blackouts of four to five hours throughout the month of January as gas remaining in the region's pipelines ran out.

Transdniestria, which split from Moldova at the end of the Soviet era and fought a brief war with the newly independent state, stands accused by Moldova and human rights organisations of jailing dissenters and limiting press freedom.

It has long relied on gas from Russian giant Gazprom shipped through neighbouring Ukraine, with Russia providing the gas free as "humanitarian assistance". But Kyiv authorities halted the transit accord on January 1 on the grounds it helped Russia's war effort in nearly three years of conflict.

The region's authorities have pledged to use a $165 million Russian credit for further gas purchases. Moldovan sources with knowledge of the deal said it would involve payment to companies in the United Arab Emirates or Saudi Arabia for shipments of gas from Hungary to Moldova.

Under the first stage of the plan now being implemented, 20 million euros of EU funds were used to buy gas for the region and 10 million euros to help government-controlled areas of Moldova purchase electricity from European suppliers.

Most power for Moldovan regions under government control has long been produced by a thermal plant inside Transdniestria, but authorities determined it was cheaper to buy it from elsewhere.

The gas rescue package devised by the EU has given rise to a new debate about how the separatist region could again become part of Moldova after more than 30 years on its own.

President Maia Sandu, who is spearheading Moldova's drive to join the EU, told a television interviewer on Thursday that a reintegration plan would cost hundreds of millions of euros annually and Moldova would need external help to implement it.

(Reporting by Alexander Tanas; Writing by Ron Popeski; Editing by Jamie Freed)

An economic crisis has slashed power use in Pakistan, which gets more than a third of its electricity from natural gas, saddling it with excess capacity it still needs to pay for, under decade-old contracts with independent power producers.

"The Qatar agreement is costly, and we will negotiate better terms next year," Musadik Malik told a parliamentary committee on energy, the paper added.

Pakistan deferred for year a deal to buy liquefied natural gas from Qatar and will now receive the contracted LNG cargoes in 2026 instead of 2025, Malik said in December, citing a surplus in LNG.

At the time he said deferring the deal brought no financial penalties, adding that Pakistan deferred five LNG cargoes from Qatar and was negotiating to defer five more with other markets, without disclosing the names of the sellers.

The petroleum ministry did not immediately respond to a Reuters request for comment.

(Reporting by Ariba Shahid in Karachi; Editing by Clarence Fernandez)

The most populous Arab country last year returned to being a net importer of natural gas, buying dozens of cargoes and abandoning plans to become a supplier to Europe amid a steep decline in domestic output.

Egypt's domestic supplies fell to a seven-year low in September 2024, according to data from the Joint Organizations Data Initiative, mainly due to declining production from Zohr gas field and higher power consumption.

"The deals shall cover most of the country's demand in 2025," the sources said.

(Reporting by Marwa Rashad; Editing by Susanna Twidale, Kirsten Donovan)

E.ON announced the deal in December, which is subject to approval from Romanian authorities. MVM gets a large chunk of its gas from Russia, unlike energy providers in most European countries, and Romania's energy ministry said in January that the sale could be blocked on security grounds.

Romania's energy ministry said it was concerned about MVM's ties with Russia, and about the possibility that the Romanian energy provider could be sold later to an entity outside the European Union.

MVM CEO Karoly Matrai told portfolio.hu that MVM had no intention of divesting the companies it plans to acquire in Romania and said that MVM would supply its Romanian customers using local gas sources.

"Transporting Russian gas to Romania would impose enormous transit costs on us," he said.

"Since domestic supply is always the most cost-effective option, if we receive approval for the transaction, we plan to supply our Romanian subsidiary primarily from local gas sources," Matrai said.

Matrai added that MVM anticipates the necessary approvals could be secured by the end of the second quarter and "that the planned June-July closing schedule will be achievable".

E.ON Energie Romania is one of Romania's biggest gas and electricity providers, serving around 3.4 million customers.

Matrai also said that diversification was important but liquefied natural gas shipments were not competitive in price with Russian gas imported via pipeline to Hungary.

He said the company traded around 12-13 billion cubic meters of gas every year, with Russian shipments accounting for about 40% of volumes.

(Reporting by Krisztina Than and Anita Komuves. Editing by Mark Potter)

In an interview with Reuters, TotalEnergies CEO Patrick Pouyanne said he believed President Donald Trump’s administration will implement pragmatic policies that will support U.S. energy production even as the world faces a new era of tariffs and trade wars.

“What they want is very simple: jobs and billions of dollars in the U.S.,” he said.

Since becoming CEO in 2014, Pouyanne has shifted Total’s focus away from Russia to low-cost oil and gas production in the Middle East, Brazil, and the U.S., while also growing electricity and renewables.

TotalEnergies reported on Wednesday that it made $18.3 billion last year, as a strong LNG trading division offset weak oil refining profits.

While rivals including Chevron, ExxonMobil and BP invested heavily over the past decade in shale oil and gas production, the French firm has largely opted to invest in LNG projects that have given it access to more than 10 million metric tons of U.S. LNG annually to supply global customers.

“We have enough to grow the U.S. position for the next decade, and I’m sure we’ll do it,” he said.

Pouyanne, 61, said TotalEnergies could invest in expansion projects at its Cameron and Rio Grande LNG facilities on the Gulf of Mexico.

“We can extend Cameron LNG," he said, adding a fourth train, or production facility. "We can extend Rio Grande," he said, to include a fifth, sixth or seventh train.

The U.S. is expected to nearly double its LNG export capacity by the end of the decade. Some economists have warned this could constrain domestic supplies and lead to higher energy bills for Americans, which could then prompt Trump to reconsider his stance on LNG exports.

Pouyanne said that the U.S. has abundant gas supplies due to its vast shale reserves, but that the country needed to invest in pipeline infrastructure to deliver the gas to demand centers along the coasts.

“If you look at the history of the evolution of the U.S. gas price, the spikes are more linked to the lack of infrastructure than the lack of resources,” he said.

EUROPEAN SUPPLY WORRIES

Europe has become the main buyer of U.S. LNG since losing access to Russian supplies following Moscow’s invasion of Ukraine in February 2022.

While Total has become a major supplier of that American LNG, the company has also continued to supply Russian LNG to Europe from that country's Yamal LNG export facility.

Pouyanne said Total’s ability to source the superchilled gas from all geographies will help it minimize the risk to profits from tit-for-tat tariffs like those between China and the U.S.

“Fundamentally it’s a political game, because China’s purchase of U.S. energy is quite limited – in fact, they purchase from portfolio companies like us. What we will do is take more LNG from Qatar or from Australia, and the US LNG we will send to other customers,” the CEO said.

Even so, Pouyanne cautioned Europe away from banning Russian LNG before 2027, saying the market would not be able to reroute 18 million tons of Russian supply until new projects start up worldwide.

He instead urged the European Union to negotiate with Trump for guaranteed LNG, sign more long-term contracts and to reconsider its carbon taxes, which have driven up the cost of electricity.

(Reporting by America Hernandez in London; Editing by David Gregorio)

The Norwegian oil and gas producer said its adjusted earnings before tax for October-December fell to $7.90 billion from $8.56 billion a year earlier. That beat the $7.71 billion expected in a poll of 24 analysts compiled by Equinor.

Equinor's Oslo-listed shares closed down 4.1%, underperforming a 0.3% rise for Europe's oil and gas index. Year-to-date, the shares are up 0.4%, lagging a 6% gain in European petroleum stocks.

Jefferies analyst Giacomo Romeo said Equinor's planned payout to shareholders in 2025 was lower than expected, while spending cuts on renewables were anticipated.

The ordinary cash dividend for the fourth quarter was raised to $0.37 per share from $0.35 in the third. Including share buybacks, Equinor plans to return to shareholders a total of $9 billion this year. 

Chief Executive Anders Opedal told Reuters the capital distribution was "competitive". 

"Equinor is well positioned for further growth and competitive shareholder returns ... Our oil and gas production outlook is increased to more than 10% growth from 2024 to 2027," he said.

In 2030, the company expects to produce around 2.2 million barrels of oil equivalent per day in oil and gas, up from the previous plan of 2 million, Equinor said in a statement.

At the same time, the company scaled back plans for renewable energy capacity expansion, in line with European peers Shell and BP.

"Inflation, interest rates, supply chain issues and regulatory uncertainty reduce the pace of energy transition ... We adapt to these realities, both phasing and prioritising investments to maximize returns, Opedal told an investor presentation. 

The company reduced its 2030 target for renewable energy capacity to between 10-12 gigawatts from 12-16 gigawatts previously, and scrapped plans to spend more than 50% of its gross capital on renewables and low-carbon solutions by 2030. 

It also reduced organic capital spending plans for 2025 to $13 billion, down from guidance of $14 billion to $15 billion a year ago. 

"The result of the above change appears to be a business that has moderated the pace of its transition, which should in theory mean more robust cash flows over time," RBC Capital Markets analyst Biraj Borkhataria said in a note to clients.

In 2025, Equinor's plans to increase oil and gas production by 4% from 2024, as new fields are set to come on stream.

Kjetil Hove, Equinor's head of Norwegian operations, told Reuters he expected the Johan Sverdrup oilfield, the largest in Europe, to produce at around 720,000 barrels of oil equivalent per day in 2025, close to the levels in 2023-2024. 

Its Troll gas field, which hit a record output last year, was also expected to continue producing at elevated levels this year, he added.

Equinor in 2022 overtook Russia's Gazprom as Europe's biggest supplier of natural gas when Moscow's invasion of Ukraine upended decades-long energy ties. Norway now meets around one-third of the continent's demand.

(Reporting by Nora Buli in London and Nerijus Adomaitis in Oslo; Editing by Gwladys Fouche, Subhranshu Sahu and Kim Coghill and Mark Potter)

How will this reshaping of American energy policy affect domestic markets? What role will technological innovation play in bridging competing priorities? And how might this transformation impact the delicate balance between energy security and climate considerations?

This week host Jason Bordoff talks with Paul Dabbar about the Trump administration’s energy agenda, and its focus on national security and energy affordability.

Paul is the chairman and CEO of Bohr Quantum Technologies and a non-resident fellow at Columbia’s Center on Global Energy Policy. He has spent the last few months leading the efforts of the incoming Trump administration to put together the U.S. Department of Energy. Paul served as the fourth undersecretary of energy for science during the first Trump administration.

Listen to podcast by Center on Global Energy Policy at Columbia University.

The statements, opinions and data contained in the content published in Gas Expert Insights are solely those of the individual authors and contributors and not of the publisher and the editor(s) of Natural Gas World.

Japan's domestic LNG demand continued to fall last year, dropping by 0.4% to 66 million tons due to a weaker economy, a growing share of renewable energy, and nuclear power plant restarts.

Yuya Hasegawa, a division director at Japan's Ministry of Economy, Trade and Industry (METI), told a conference in Tokyo that there is an expectation that power demand will expand due to the growth of data centres in the country.

"If we do not have a huge expansion of renewable energy, or if we cannot reduce the cost of hydrogen, ammonia, CCUS (carbon capture, utilization and storage), our gas demand will increase," he said.

According to Hasegawa, under an alternative energy strategy scenario being prepared by METI, Japan's LNG demand will rise to 74 million tons in 2040, or by almost 10%, if renewable energy expansion is not there as other METI scenarios assume.

Australia, Malaysia and the United States are the biggest LNG suppliers to Japan, but Canada is preparing to start exports to Japan later this year from the LNG Canada project where Mitsubishi 8058.T is a shareholder.

With U.S. President Donald Trump still threatening steep tariffs on Canada, including on energy imports, Canada is turning its attention to other potential markets, including Japan, the world's second biggest LNG buyer after China.

Trump has also promised to increase oil and gas production in the U.S., already the world's biggest, increasing competition among sellers for top buyers, including for Japan.

Canada's province of Alberta, a source of gas for the yet-to-be-launched LNG Canada export project, wants to double production for supplies elsewhere, including to Asia and Japan, Rebecca Schulz, minister of environment and protected areas at the Government of Alberta, told the same conference in Tokyo.

"Just the shipping time, half of the time coming from the U.S. Gulf Coast, it makes us a perfect partner (for Japan)," she said.

(Reporting by Katya Golubkova; editing by Philippa Fletcher)

China, the world's biggest importer of the three energy commodities, on Tuesday slapped import duties of 15% on U.S. LNG and coal, and 10% on crude oil and farm equipment.

Beijing's move came after the Trump administration imposed an additional 10% tariff on all imports of Chinese goods into the United States.

While the 10% impost was lower than the up to 60% threatened by Trump during his campaign last year to reclaim the U.S. presidency, it was still enough to prompt an immediate response from China.

China's reaction raises the risk of further moves by the United States, and ratchets up the trade tension between the world's two largest economies.

The risk is that a series of tit-for-tat measures causes global economic growth to slow and inflation to rise as countries have to re-order supply chains and deal with increased disruptions to industries such as manufacturing and construction.

However, the immediate impact of China's measures on imports of U.S. crude, LNG and coal is likely to be limited.

China imported 5.99 million barrels of crude from the United States in January, according to commodity analysts Kpler.

This is equivalent to about 193,000 barrels per day, which is less than 2% of China's total imports.

The January imports were typical of volumes in recent months, although China has imported more U.S. crude on occasion, with the 948,000 bpd of June 2023 being the highest in the past two years.

China's LNG imports from the United States have also been modest in recent months, with January coming in at 190,000 metric tons, down from 220,000 tons in December.

The LNG volumes have been fairly volatile, reflecting the spot nature of the trade between the United States and China, but the highest in the past two years was 780,000 tons in October last year.

China's total LNG imports have been averaging around 6.5 million tons a month recently, meaning the U.S. is supplying in a range between 4% and 12% of the total.

China's imports of coal from the United States were 1.34 million tons in January, according to Kpler, with the strongest month in the past two years being 1.55 million in August last year.

Official customs data showed China's total coal imports averaged 45.2 million tons per month in 2024, making the U.S. little more than a fringe supplier.

BROADER IMPLICATIONS

Given that both China and the United States can probably adapt without too much inconvenience to Beijing's tariffs on energy imports, the question then becomes whether it matters.

The answer is that it amplifies tensions and accelerates the trend of increasingly splitting the world into two trading blocs, one that does business with Trump's America and its allies, and one that prefers to deal with China and what has been described as the global south.

The risk is that Trump continues to attack both his traditional allies and rivals with tariffs as part of his "America first" agenda, a policy that may serve to drive commodity producers more towards the emerging BRICS trading bloc.

China is also flexing its muscle in commodities by announcing new export controls on five minerals that are used in defence and energy transition industries.

The controls, which come into effect immediately, cover the metals tungsten, tellurium, bismuth, indium and molybdenum and their related products.

The measures make it more likely that Western nations will seek to find and develop their own supplies.

But this will mean having to engage with companies and governments in Africa, Asia and Latin America, many of which are likely to be targets of Trump's tariff and aid measures.

(Editing by Mark Potter)