• Southeast Asia is considering the highest number of final investment decisions (FIDs) on oil and gas extraction projects this decade, with over 20 billion cubic metres annually (bcm/y) of new production capacity potentially added — an 18% increase over current output that threatens to lock the region into decades of fossil fuel dependency.
• These FIDs have faced a history of delays, so the likelihood of these projects moving forward remains unclear.

Data in Global Energy Monitor’s Global Oil and Gas Extraction Tracker (GOGET) show that 2025 could mark a pivotal year for upstream gas development in Southeast Asia, with one project already approved and thirteen other gas projects potentially reaching FID (Figure 1). These include five projects in Indonesia, two in Malaysia, four in Vietnam, one in Brunei, and one in Myanmar (Appendix 1). If all projects are approved, they would not only represent the highest annual count of upstream approvals in over a decade but also unlock more than an estimated 20 bcm/y of additional gas production capacity, an 18% increase over current output. This would signal a strategic regional pivot towards accelerating gas development. 

Figure 1: Gas projects in SE Asia with FIDs (completed or anticipated) in this decade¹

Figure 2: Years of delay since the initial expected FID for SE Asia gas extraction projects expecting FIDs in 2025. Ordered and scaled by anticipated peak production in billion cubic meters per year (bcm/year)²

These new fields come despite clear evidence that new oil and gas fields are incompatible with limiting global warming to 1.5°C.  Additionally, the long-term economic and environmental risks of such a fossil-heavy path are substantial, especially given the region’s parallel commitments to climate goals, energy transition, and ecosystem conservation. These projects are located in ecologically sensitive areas, and gas development could have significant negative impacts on the biodiversity found there.

Upstream gas expansion is being positioned by national governments as both a stopgap to address short-term energy needs and a catalyst to national development.  Since companies and countries are unlikely to abandon gas developments before reserves are fully depleted in order to ensure a complete return on investment, these developments would have a significant lifespan and would lock in gas as a substantial component of the region’s energy mix. 

At the same time, many of these projects have faced a history of delays, and significant uncertainty exists around the likely progress of these projects (Figure 2).

Upstream gas development threatens important biodiversity

Southeast Asia’s midstream and downstream gas infrastructure in development — projects that have been announced or are in the pre-construction and construction phases — remained largely stable over the previous year, with over 100 gigawatts (GW) of gas-fired power capacity, around 46 million tonnes per annum (mtpa) of liquefied natural gas (LNG) import capacity, and 15 mtpa of LNG export capacity in development. In contrast, upstream gas extraction is poised for a potential phase of rapid expansion.

Many of these exploration and extraction activities are encroaching on ecologically sensitive regions like the Coral Triangle and the Mekong Delta. The Coral Triangle — an area of ocean around Malaysia, Indonesia, and other countries — is sometimes referred to as the “Amazon of the seas” due to its incredibly high level of marine diversity. Over 120 million people rely on the resources found there for their livelihoods.

However, about 16% of the protected area in the Coral Triangle overlaps with gas blocks, most of which are still in the exploration phase. For instance, block SB-403, where gas exploration is imminent, is located entirely within the Tun Mustapha Marine Park in Malaysia. If all current proposals go into production, more than 1.6 million square kilometers of the Coral Triangle would be directly impacted by fossil fuel development.

Located immediately to the north of the Coral Triangle, the Mekong Delta of Vietnam is one of the largest and most fertile deltas in the world, supporting a population of 18 million people. The health of the delta and the people who depend on it is currently threatened by gas discoveries in lease blocks that overlap the delta. As in the Coral Triangle, gas development here significantly threatens the health of the natural life and human communities who live there.

Malaysia

As one of the top five global exporters of LNG, Malaysia is pursuing ambitious upstream gas development plans. In its Activity Outlook 2025–2027, state-owned energy company Petronas announced its intention to increase national oil and gas production from 1.7 million barrels of oil equivalent per day (boe/d) in 2024 to 2 million boe/d by 2027. This target will be met through a mix of greenfield and brownfield projects.

When the Lang Lebah field was discovered in 2019, Petronas wrote of how it was “highlighting just how prolific Malaysia’s basins are” as a harbinger of “potentially more discoveries to come.” As of September 2023, the project was “on track” to reach FID before the end of the year. However, by February 2025, the FID was “now delayed until at least 2026” due to costs and corporate politics. The field is anticipated to produce 0.03 bcm of gas per day, or about half of Petronas’ intended marginal increase.

Other notable developments include the Kasawari gas project off the coast of Sarawak and the redevelopment of mature fields such as Gumusut-Kakap and Bekok. Petronas produced first gas from the Kasawari field thirteen years after its discovery in 2024, a year later than anticipated. The field is expected to extract 84 bcm of gas, according to GOGET, and will supply gas to Petronas’ LNG Complex in Bintulu and to domestic consumers.

To further stimulate investment and exploration, Petronas has launched the Malaysia Bid Round 2025, offering new blocks in the Malay and Penyu Basins offshore Peninsular Malaysia and the Sandakan Basin off Sabah. Recently, Petronas has also signed a memorandum of understanding with Italy’s Eni to jointly manage upstream assets in Malaysia and Indonesia. This partnership involves combined reserves of approximately 3 billion barrels of oil equivalent, with exploration potential estimated at an additional 10 billion barrels.

Despite the continued expansion of upstream activities, Malaysia’s National Energy Policy 2022–2040 signals a strategic shift, targeting a reduction in gas’ share of the national energy mix to 39% by 2040. The country has also committed to reaching net-zero greenhouse gas emissions as early as 2050. However, continued upstream gas exploration contradicts this trajectory. Petronas’ investment in the Kasawari carbon capture and storage (CCS) project is insufficient to neutralize the climate impact of ongoing gas development. The effectiveness and long-term viability of CCS remain unproven, and a recent study suggests that the CCS proposals may even result in increased emissions by extending the extraction and use of fossil fuels.

Indonesia

Indonesia is aiming to expand gas extraction, pushing for new upstream gas development to meet both domestic and international energy demands. Eni’s US$12 billion “giant” Geng North gas discovery is one of the biggest and fastest-moving developments. Utilizing existing infrastructure, such as the LNG plant in East Kalimantan, the project is set to begin production in late 2027. Eni describes its Kutei Basin production hub as a “game changer.” According to a spokesperson from SKK Migas, Indonesia’s oil and gas regulator, the Geng North discovery “has a very strategic meaning for Indonesia’s oil and gas in the future,” helping to revitalize investor confidence and bringing Indonesia “back to being an exploration destination.”

The Abadi gas field and associated LNG project are additional examples of delayed ventures. Discovered in 2000, INPEX’s project “has long struggled to gain traction.” A development plan was approved by the Indonesian government in 2019, but then “to make the project cleaner” INPEX submitted a revised plan in 2023. At that time, the company indicated it was targeting FID in the “latter half of the 2020s” to begin extracting in the 2030s. Listed as a “National Strategic Project,” Abadi would reportedly supply gas to the Abadi LNG project at a rate of 13 bcm/y of LNG, 1.5 bcm/y of pipeline gas.

Another significant investment in this sector is BP’s US$7 billion Tangguh Ubadari, CCUS, and Compression (UCC) project, approved in October 2024. This project is expected to unlock 3 trillion cubic feet of additional gas, incorporating CCUS to enhance gas recovery and reduce emissions.

Indonesia’s ambitious expansion is closely tied to its Upstream Oil & Gas (IOG) 4.0 Strategic Plan, led by SKK Migas, which aims to boost gas production to 12 billion standard cubic feet per day by 2030. To support this, the government has announced plans to offer 54 new oil and gas blocks between 2024 and 2028, making it easier for investors to explore and develop new projects. According to Minister of Energy and Mineral Resources Arifin Tasrif, Indonesia currently has estimated recoverable gas reserves of about 54 trillion cubic feet, with an aim to double that amount following exploration activities. In the past twelve months, Indonesia awarded oil and gas licenses with potential emissions of 54.4 MtCO2.

However, this strong focus on gas development raises questions about its alignment with Indonesia’s long-term energy transition goals. Under the Just Energy Transition Partnership (JETP) scenario, gas consumption is projected to peak at 90.6 terawatt hours (TWh) (6.11%) in 2030, before gradually declining to 38.3 TWh (2.58%) by 2050.  Heavy investments in new gas infrastructure, particularly if paired with efforts to increase demand, could significantly delay the shift toward renewable energy.

Vietnam

Vietnam is making a strategic effort to accelerate upstream gas development in order to meet rising energy demand, enhance security, and reduce dependence on coal. Central to this effort are two major offshore gas extraction projects: Blue Whale (Ca Voi Xanh) project and Block B project.

The Ca Voi Xanh gas field located in Block 118, about 88 km off Vietnam’s central coast, was discovered by ExxonMobil in 2011.  It is considered Vietnam’s largest gas field, with reserves estimated at 150 bcm. The planned development includes offshore extraction facilities, an 88-km pipeline to the Quang Nam province, and a 3,000 megawatt (MW) power generation capacity. Despite being included in both Vietnam’s Power Development Plan (PDP) VII and VIII, the project has made limited progress. Minister of Industry and Trade, Nguyen Hong Dien, acknowledged the challenges, citing ExxonMobil’s corporate restructuring and strategic pivot toward new energy as key factors slowing development. While cancelling the project is not an option under consideration, Dien stated that further progress will be very difficult under the current circumstances. As an interim measure, the gas-fired power plants could initially operate using imported LNG, with a long-term plan to transition to domestic supply from the Blue Whale field once it is brought into production.

Located in the southwest offshore region, the Block B gas project is another ambitious upstream undertaking, with gas reserves estimated at 107 bcm. The project includes extensive subsea pipelines and supporting infrastructure, with an investment of over US$10 billion.

These upstream gas projects are considered part of Vietnam’s energy transition and aligned with its Power Development Plan VIII (PDP8), which is attempting to reduce emissions from coal while renewable energy capacity is expanded. However, heavy investment in gas can lead to gas lock-in and may divert needed financing away from renewables.

Brunei Darussalam

Brunei Darussalam has recently intensified its upstream gas development efforts. In February 2025, the country launched its first licensing round in over a decade, offering two offshore blocks for competitive bidding, with awards expected in 2026. This initiative reflects Brunei’s commitment to attracting foreign investment and expanding gas exploration. The nation is also progressing with key deepwater gas projects, including the Merpati-Meragi and Kelidang Cluster fields. The Merpati-Meragi field, discovered in 1992 and located offshore, is slated to begin commercial production in 2025 with a projected development cost of US$1.8 billion. Similarly, the Kelidang Cluster — comprising the Kelidang North East and Keratau gas fields and discovered in 2013 — is expected to reach FID in 2025 and commence production in 2025, with estimated development costs of US$5.5 billion.

Brunei’s continued upstream gas exploration and development efforts are increasingly inconsistent with its long-term policy goals. Wawasan Brunei 2035 sets out a national vision for a diversified, knowledge-based economy that maintains high living standards while reducing reliance on hydrocarbons. Diversification away from the oil and gas industry is recognized as essential to building resilience against global market volatility and ensuring future sustainability.

Brunei’s Economic Blueprint further acknowledges that heavy dependence on oil and gas has contributed to low economic growth and high unemployment, identifying five priority sectors — alongside other emerging industries — that will drive the development of the country’s non-oil and gas sector and support national economic diversification efforts. The Brunei National Climate Change Policy (BNCCP), launched in 2020, reinforces this strategic direction by committing Brunei to achieving net-zero greenhouse gas emissions by 2050. The BNCCP sets ambitious targets, including increasing the share of renewable energy to 30% of total power generation by 2035, highlighting a clear pivot toward a low-carbon economy. In this context, the pursuit of continued upstream gas development fundamentally undermines Brunei’s commitments to economic diversification and sustainable development.

Conclusion

New and expanded gas production in Southeast Asia threatens the region’s biodiversity and the livelihoods of the communities who depend on it. It risks significant economic, ecological, and cultural damage and the further entrenchment of gas in these countries’ energy mixes. The investment and further establishment of the gas industry would likely present a barrier to the development of renewables.

Several of these high-profile projects have already faced years of delays. As the energy transition gains momentum, the viability of these stalled developments should be re-assessed. Rather than pursuing high-risk fossil fuel ventures, Southeast Asian governments have a critical opportunity to redirect investment toward clean, scalable energy systems that support economic resilience and align with global climate commitments. Persistent delays and uncertainty surrounding gas extraction should catalyze these countries to focus on the development of renewables instead.

Appendix 1: Top gas fields in Southeast Asia with a potential 2025 FID 

*Production design capacity or peak annual production. Typically, projects have a 1-3 year ramp-up period. 

¹ Updates made to reflect new information released since the Feb 2025 data release

¹  Updates made to reflect new information released since the Feb 2025 data release.

² Updates made to reflect new information released since the Feb 2025 data release.

³ Mentarang-PowerChina, Upper Cisokan-CEEC, Batang Toru-PowerChina, Kerinci Merangin-Hydget Power.

About the Asia Gas Tracker

The Asia Gas Tracker is an online database that identifies, maps, describes, and categorizes gas infrastructure across Asia, including gas pipelines, liquefied natural gas (LNG) terminals, gas-fired power plants, and gas fields. Developed by Global Energy Monitor, the tracker uses footnoted wiki pages to document each project and is updated annually.

About the Global Oil and Gas Extraction Tracker (GOGET)

GOGET is an information resource on gas oil extraction projects. The internal GOGET database is updated continuously throughout the year, and the annual release is published and distributed with a data download, summary tables, and field-level wiki pages. The data are released under a creative commons license. Commercial datasets exist but are prohibitively expensive for many would-be users. Global Energy Monitor developed GOGET so that high-quality data on these projects is available to all.

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Warda Ajaz

Asia Gas Tracker Project Manager

warda.ajaz@globalenergymonitor.org

The post Southeast Asia ramps up gas extraction plans but uncertainty remains appeared first on Global Energy Monitor.

• The vast majority of new oil and gas extraction projects in 2024 are located in the oceans: At least 8 billion barrels of oil equivalent (bboe) of resources were announced in new offshore discoveries, nearly 4 bboe of reserves were sanctioned for development offshore, and about 6.5 bboe began to be tapped as offshore projects started up, all marginal increases over 2023.
• 85% of new discoveries by volume were located in ten offshore fields.
• At least twelve projects reached a positive Final Investment Decision (FID) in 2024, all of which were offshore.
• 19 offshore projects produced first oil or gas in 2024, 71% of the total volume of field startups.
• Offshore oil and gas put oceans at risk throughout projects’ life cycles, jeopardizing marine biodiversity locally and the climate globally.

Global Energy Monitor’s Global Oil and Gas Extraction Tracker (GOGET) shows that the vast majority of new projects discovered, sanctioned, and started up in 2024 are located in the oceans. The industry continues to ignore warnings of the risk oil and gas extraction causes, leading to extreme climate impacts. Instead, companies and countries continue to push into uncharted waters. Not only do these projects harm the ecosystems they exist in and run the risk of environmental catastrophes, they run afoul of the scientific consensus that any new oil and gas field is incompatible with limiting warming to 1.5°C and break clear calls to protect the climate.

Ramping up offshore

Globally, on and offshore, at least 9 billion barrels of oil equivalent (bboe) of resources were announced in new discoveries, nearly 4 bboe of reserves were sanctioned for development, and about 6.5 bboe began to be tapped as projects started up. Discoveries, project approvals, and startups all have marginal increases in offshore volumes percentages compared to 2023. This is in line with longer term trends of the growth in prominence of offshore development.

Figure 1

Discoveries

Of these discoveries, 85%, in terms of expected hydrocarbon extraction, were located in ten offshore fields. Two of the largest of these projects were the Nokhatha and Mopane fields in Kuwait and Namibia, respectively. These giant discoveries were both the products of a renewed offshore focus from their respective countries and were welcomed by fossil fuel promoters as indications of potential expansions of oil and gas activity in these areas.

The Kuwait Petroleum Corporation (KPC), the owner of Nokhatha, through its subsidiary Kuwait Oil Company, made the “breakthrough” discovery as part of an offshore exploration campaign. Following Nokhatha’s announcement in 2024, the Julaiah field was discovered in January 2025, raising interest in the area.

Mopane follows significant discoveries in 2022 and 2023 (see Drilling Deeper), amidst the “Oil exploration boom Namibia.” Unlike Kuwait, Namibia has not yet produced any oil or gas. Following Galp’s discovery of Mopane in the Orange Basin, the area has been called “industry’s most exciting exploration frontier.”

Figure 2

Project approvals

At least twelve projects reached a positive Final Investment Decision (FID) in 2024, all of which were offshore. FID signifies the start of a project’s development in GOGET, strongly indicating that the company actually intended to develop a project.

The Americas held significant activity in this regard. Exxon sanctioned the Whiptail development, targeting about 1 bboe of oil and gas, aiming to start production in 2027, and costing around US$12.7 billion. TotalEnergies announced FID of the GranMorgu development in Suriname in October 2024. Targeting the Sapakara and Krabdagu oil discoveries, the GranMorgu project is located right next to the maritime border with Guyana, drawing hopes from industry of replicating ExxonMobil’s successful exploration. In the United States, three projects targeting around 500 million boe (mmboe) were sanctioned, and in Trinidad and Tobago, another 300 mmboe project was sanctioned. Other projects were additionally sanctioned in Africa, Europe, and Western Asia.

Figure 3

Startups

Nineteen offshore projects produced first oil or gas in 2024. These projects represent 71%  — 6.5 bboe — of the reserves started up in 2024. Significantly, China started up six offshore projects, the largest of which is China National Offshore Oil Corporation’s (CNOOC) Bozhong 19-6 (13-2) in the Bohai Sea, which commenced production in May 2024. This comes as CNOOC sets a 2025 production target of 5.6% higher than 2024 levels.

On average, this crop of projects took about fourteen years from discovery to first production, about the same time frame as onshore projects (fifteen years).

Figure 4

Putting oceans at risk

The risks from offshore drilling exist throughout the lifecycle of a project. A United Nations report recently called for, among other things, the halting of new offshore oil and gas projects until a series of safeguards and assessments is made. Such a directive was necessary, as those safeguards do not always occur. Research from the Center for International Environmental Law (CIEL) details how “offshore oil and gas activity threatens [the] two global commons on which all life on Earth depends: the oceans and the atmosphere.”

During the exploration process, noise pollution from seismic studies jeopardizes marine life, while exploratory well drilling can cause seabed disturbance and habitat loss and the introduction of toxins that threaten ecosystems. Additionally, the creation of exclusionary zones can prevent fisherfolk from accessing areas, harming their livelihoods.

During the production phase, offshore oil and gas production — like onshore production — has a huge climate footprint, but is historically underreported. Additionally, large-scale spills cause devastating impacts that have been well documented, while routine spills are an “often unreported or underreported” problem. As shown by SkyTruth, a vast portion of the oceans are impacted by oil and gas production.

Once companies have extracted all the value they can from a field, the true costs of decommissioning are shown. These potentially leaky wells can continue to harm ecosystems and the environment after a company leaves a site, especially when sites are abandoned.

Matching with trends

Historically, onshore oil and gas projects account for the majority of production. However, exploration and extraction companies are focusing offshore, with increased attention on unlocking new frontier areas via high-risk, higher-cost further offshore development. 

In November 2024, the Financial Times declared, “Offshore oil is back” quoting a Rystad Energy analyst proclaiming “this comeback looks set to make the 2020s deepwater’s decade.” Reuters explained the industry’s “love” of deepwater, stating, “all-new deepwater drilling is poised to hit a 12-year high next year.” The Gas Exporting Countries Forum (GECF) Gas Outlook outlines that many countries and companies are prioritizing offshore, and that “offshore natural gas production is forecast to grow at a faster rate than onshore gas production.” 

BP, for example, reportedly “abandoned” its target to cut its oil output and instead announced a focus on new investments in the Gulf of Mexico to boost outputs. BP sanctioned the Kaskida development in July 2024. In February 2025, Equinor’s CEO similarly stated the company would be cutting its renewable investments substantially while increasing oil and gas production. Specifically, the CEO discussed the Norwegian company’s large offshore oil field.

GOGET data are directionally aligned with global trends shown in other datasets. GOGET data show offshore discoveries have been growing in share of global discoveries per year, accounting for about 60% in the 2010s and then around 73% so far in the 2020s.

Figure 5

The oil and gas industry’s justifications

According to analysts, the costs of developing deepwater projects have halved in the past ten years. That fact, alongside new technological advances, has opened up the ocean for more production in reservoirs that were previously economically and geologically unreachable. Industry and analysts argue offshore projects have a lower carbon intensity than older projects, one even saying, “new projects are a lever to meet emission reduction goals, especially those focused on deepwater projects that continue to deliver on low emissions intensity and economic return.”

Emissions from extracting, processing, refining, methane, and transport combined, i.e. scopes one and two, account for about 20% and 15% of oil and gas lifecycle emissions, respectively, per the International Energy Agency. Combustion of oil and gas by end-use consumers accounts for 80% of oil and 85% of gas lifecycle emissions, so ignoring scope three is not accounting for the majority of climate impacts of projects, as shown in the cases of Rosebank and Jackdaw.

Local ecosystems and the global environment

While the impacts on local ecosystems, biodiversity, and economies must be addressed, as alluded to above, the environmental impact of these projects from associated greenhouse gas emissions is an additional problem. As discussed in Drilling Deeper, the science is clear that there can be no more oil and gas fields approved if the world is to limit warming to safe levels. This additional billion boe of oil and gas will only further risk climate catastrophe.

The peak of oil and gas demand is expected before 2030, but most of these projects would be just ramping up as the world’s oil and gas usage declines. Historical data show that projects often take longer than the timelines given by project promoters.

While some investment in oil and gas supply is needed in IEA scenarios, there is a significant discrepancy between what investment needs to be going toward clean energy and what is actually going towards fossil fuels. Bringing investments in line with scenarios designed to limit warming — stopping incompatible investment in fossil fuels and investing in wind and solar — could bridge the gap.

Conclusion

Offshore oil and gas appears to be having a heyday, but alternative futures are still possible. Expansions into uncharted waters are risky bets, financially, for ecosystems, and for the environment. 

Accurate, accessible data is a necessity to best understand the trends, players, and systems enabling this growth. GOGET provides data on the locations, companies involved, production, and reserves for all of these fields and about 7,000 other projects.

About the Global Oil & Gas Extraction Tracker

GOGET is an information resource on gas oil extraction projects. The internal GOGET database is updated continuously throughout the year, and the annual release is published and distributed with a data download, summary tables, and unit wiki pages. The data are released under a creative commons license. Commercial datasets exist but are prohibitively expensive for many would-be users. Global Energy Monitor developed GOGET so that high-quality data on these projects is available to all.

Acknowledgments

Charts and maps were created by Scott Zimmerman and Stephen Osserman. Editing by Stefani Cox, David Hoffman, Hanna Fralikhina and Julie Joly. Alyssa Moore, Amalia Llano, Hanna Fralikhina, Julie Macuga, Mingxin Zhang, Norah Elmagraby, and Will Lomer contributed to the research underlying this report. Julie Joly provided invaluable guidance. Special thanks to Andreas Randøy (Greenpeace, Norway), Ashlee Barnes, Jasmine Wakefield (Uplift, UK), Daan Koopman, Elvira Sumalinog, Paul Rosane (Asset Impact) and Bruna Campos (CIEL) for data feedback. Maisie Bird and Jenny Martos have also contributed to GOGET.

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Scott Zimmerman

Project Manager, Global Oil and Gas Extraction Tracker

scott.zimmerman@globalenergymonitor.org

The post Oil & gas extraction’s move offshore: Trends and risks appeared first on Global Energy Monitor.

According to new data in the Global Oil and Gas Plant Tracker, over the last year, the U.S. more than doubled its oil- and gas-fired capacity in development — those projects in the announced, pre-construction, and construction phase — totalling over 85 gigawatts (GW). This increase has propelled the country to second in the world, behind China, for oil- and gas-fired projects in development.

If all in development plants are built, the U.S.’ existing fleet would grow by 15% at an estimated cost of over US$85 billion in capital costs. If future AI power demand does not materialize, any new gas plants built risk becoming stranded assets and either being decommissioned before the end of their economic life or experiencing significant underutilization. The U.S. now leads with over a quarter of the world’s operating oil and gas power plants (556 GW).

The bulk of in-development gas-fired capacity is slated to come online between 2025 and 2030 (Figure 1). Less than one-fifth of these projects in development in the United States have progressed to construction. Nearly half are still announced, and slightly over one-third are in the pre-construction phase. Texas leads the planned gas buildout with over a quarter, or 22.6 GW, of the oil- and gas-fired power capacity in development in the U.S., but nearly 15 GW is still in the announced phase.

Figure 1

Where are proposed hyperscale data centers and in development gas plants located?

According to data from Data Center Map, the top states for in-development hyperscale² data centers are Virginia, Ohio, Georgia, Texas, and Illinois, which make up nearly two-thirds of in-development hyperscale data centers in the United States. Northern Virginia, also known as “Data Center Alley,” is the epicenter of these developments  — hosting 70% of the world’s data centers.

Figure 2

This region falls under the purview of PJM Interconnection (PJM), the largest regional transmission organization in the United States, covering thirteen states³ with half of its installed capacity coming from gas-fired generation. PJM’s peak load forecast has soared in the last few years as unprecedented demand growth from data centers and industrial electrification, combined with upcoming thermal generation retirements, has resulted in reliability concerns and demand/supply constraints. Coal- and gas-fired power capacity accounts for 90% of the forecasted 40 GW of retirements in PJM in the 2022–2030 period. 

According to GEM’s latest data, PJM has 16 GW of in-development gas-fired capacity in the U.S. Of this in-development capacity in PJM, more than half is from projects that are conversions or replacements of coal-fired power plants. Correspondingly, about 27 GW, or nearly one-third of the in-development oil- and gas-fired capacity in the U.S., is from conversions or replacements of coal-fired power plants. 

The Federal Energy Regulatory Commission (FERC) recently approved PJM’s controversial proposal to fast-track interconnection review for “shovel-ready” projects, which could favor gas plant connections to the grid, ahead of wind and solar, in order to meet near-term grid reliability issues. Two other grid operators are considering similar proposals. In addition, a recently introduced congressional bill, the GRID Power Act, aims to fast-track dispatchable generation in interconnection queues after review by FERC. 

The Electric Reliability Council of Texas (ERCOT), which manages approximately 90% of Texas’ energy load, is predicting nearly a doubling of its energy demand in the next six years, partially due to data center and crypto currency mining demand. 

Future AI power demand propelled the rise in proposed gas power in the last year, but actual energy need is uncertain

Projections vary widely about data center power demand, and corresponding load growth in the U.S., over the next five years. A recent Department of Energy-funded study shows that U.S. data center power demand could nearly triple in the next three years and consume as much as 12% of the country’s electricity, potentially requiring 33–91 GW of new generation capacity to be built by 2028. A GridStrategies study found that the five-year load growth is up fivefold over the past two years, with a forecasted 16% increase in energy demand in the U.S. by 2029. 

U.S. President Trump recently pledged to speed up the development of power plants that are co-located with AI data centers through his declared “national energy emergency,” which opens the door for loosening or cancelling environmental regulations in favor of the fossil fuel industry. Additionally, President Trump announced an AI joint venture, Stargate, that includes a $500 billion investment from companies including OpenAI, Oracle, and SoftBank.

Days after Trump’s announcement, a Chinese AI startup, DeepSeek, upended power forecasts and caused power and tech stocks to plummet, with its open-source model, which delivers performance at a fraction of the cost and energy of Big Tech’s AI chatbots and counters the idea that large amounts of energy will be needed to power AI.

In addition, a flurry of announcements came from companies new to gas-fired power generation, including NextEra Energy partnering with GE Vernova, to develop gas-fired power plants to power AI data centers. Traditional Big Oil companies ExxonMobil and Chevron are also seeking to build gas plants that would directly supply data centers.

A recent Institute for Energy Economics and Financial Analysis (IEEFA) study, which examines rising forecasted load growth tied to data center growth for select Southeast utilities, warns that there is a risk of overbuilding gas infrastructure if the forecasted data center demand is not realized.

Rapidly deployable and scalable renewables are better suited to incrementally meet data center energy growth

Construction costs⁴ and lead times for securing gas turbines are increasing. NextEra Energy, which operates the largest gas-fired fleet in the United States, showed in their most recent earnings call that not only is unplanned gas generation not available until 2030 or later, but renewables and storage are “ready now and fast to deploy” and cheaper than new build gas power. With the gas power plant buildout facing longer construction timelines, supply constraints, and rising costs, renewables combined with battery storage are better positioned to meet an immediate rise in power demand. The levelized cost of electricity (LCOE) for solar and onshore wind are cheaper than any other source, including gas, in the U.S., according to Lazard’s latest report.

¹ Estimate is based on CCGT capital costs ($1000/kW) for the U.S. from IEA World Energy Model inputs.

²Very large data center facilities with power capacity of 40 MW or greater.

³Including all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia.

⁴GE Vernova’s most recent earnings call states new combined-cycle builds costing $2,000 per kilowatt and rising, a drastic increase from a few years ago.

About the Global Oil & Gas Plant Tracker

The Global Oil and Gas Plant Tracker (GOGPT) is a worldwide dataset of oil- and gas-fired power plants. It includes units with capacities of 50 megawatts (MW) or more (20 MW or more in the European Union and the United Kingdom). For internal combustion units, or those units that have multiple identically-sized engines, the 50 MW capacity unit threshold applies to the total capacity of the set of engines. The GOGPT catalogs every oil- and gas power plant at this capacity threshold of any status, including operating, announced, pre-construction, construction, shelved, cancelled, mothballed, or retired. Units often consist of a boiler and gas or steam turbines, and several units may make up one power station.

About Global Energy Monitor

Global Energy Monitor (GEM) develops and shares information in support of the worldwide movement for clean energy. By studying the evolving international energy landscape and creating databases, reports, and interactive tools that enhance understanding, GEM seeks to build an open guide to the world’s energy system. Follow us at www.globalenergymonitor.org and on Bluesky @GlobalEnergyMon.bsky.social and Twitter/X @GlobalEnergyMon.

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• A sprawling hydrogen network is planned across Europe, including twelve projects that would expand or convert liquified natural gas (LNG) terminals to import hydrogen derivatives, 50,165 kilometers (km) of hydrogen gas pipelines, and 44.6 gigawatts (GW) in gas-fired power capacity proposed to burn hydrogen, per a new, comprehensive survey of European hydrogen infrastructure conducted by Global Energy Monitor (GEM). A hydrogen network of this scale, with power production as a major end use, is impractical and unrealistic as a decarbonization strategy.
• Europe’s hydrogen plans follow the rapid LNG infrastructure growth set off by Europe’s gas crisis, which led Europe’s import capacity to increase by 31% since February 2022. Five projects came online this year, amounting to 28.7 billion cubic meters per year (bcm/y) in new LNG import capacity, but the pace of new proposals has nearly ground to a halt with just one new import project mooted in 2024.
• The proposed system of hydrogen-capable pipelines is over 40% longer than what GEM had recorded in the March 2024 Europe Gas Tracker report, and it is equivalent to two-fifths the length of the existing European gas transmission pipeline network. 
• Germany has among the most hydrogen projects in planning across each of the three types of infrastructure, with one-half of the import projects, one-fifth of the pipeline length, and almost one-third of hydrogen-burning power capacity in development in GEM’s dataset.
• Many hydrogen projects lack core details, such as start years and blending percentages, indicative of their tentative nature and the risk that they could lock in fossil fuel consumption if they move forward without credible plans to use green hydrogen. For instance, among twelve hydrogen derivative import terminals just three have defined capacities and five have set start years.
• Europe’s hydrogen infrastructure plans are still relatively immature, and only a fraction of these projects may ultimately materialize. No hydrogen derivative import projects have begun construction or taken final investment decisions (FIDs) indicating they will move forward, and just one hydrogen gas pipeline is currently being built. Among hydrogen power proposals, several pilot projects have begun operating with small amounts of hydrogen, but almost three-quarters of all capacity is still in the earliest announced phase. The vast majority of power projects have also not secured financing or contracts for green hydrogen supplies.

In the wake of Europe’s rush to build LNG import terminals, sparked by Russia’s invasion of Ukraine, a new infrastructure buildout is taking shape. A network of hydrogen-capable infrastructure including terminals, pipelines, and power plants is being developed with support from European governments. Hydrogen produced by renewable energy, referred to as green hydrogen, could be an important decarbonization tool in certain applications, such as industrial processes where fossil-based hydrogen is used today. However, a hydrogen network of this scale, with power production as a major end use, is a flawed decarbonization strategy. Hydrogen is inefficiently transported via terminals and pipelines, and it is inefficient and expensive as a fuel for baseload power generation. The elements of Europe’s hydrogen plans that build on its methane gas network appear, at best, out of touch with the science and economics of hydrogen, and, at worst, like an attempt by the oil and gas industry to extend the lifetime of Europe’s dependency on gas.

It is incumbent on Europe’s governments to prioritize policy support and investments for green hydrogen projects in sectors where hydrogen is the best or only decarbonization solution, and to ensure that gas infrastructure operators and project promoters have concrete, realistic plans to transition from gas to green hydrogen. At present, European Union (EU) policy is not targeted enough to ensure that limited green hydrogen resources are used effectively.

For the first time, Global Energy Monitor (GEM) offers one of the most comprehensive overviews of the intersection between the proposed hydrogen network and existing European gas infrastructure. GEM’s data include 1) import terminals for hydrogen derivatives (i.e., hydrogen, ammonia, and “synthetic LNG”) associated with existing LNG projects, 2) hydrogen gas pipelines, and 3) hydrogen-burning proposals at gas-fired power plants in development. GEM finds that the majority of these projects are still in early stages and have not advanced to construction or other key milestones. Crucially, planning is far behind for renewable hydrogen production projects that would supply the hydrogen network, according to the International Energy Agency (IEA). The hydrogen hype could well prove to be a bubble.

Meanwhile, as of 2024, the buildout of European LNG infrastructure appeared to be slowing. Several major projects came online last year, but the pace of new proposals has nearly ground to a halt. As European gas demand begins to fall, these projects are unnecessary and risk wasting public and private investment. Transmission projects originally proposed for methane gas, only to be reenvisioned by their developers for hydrogen gas, indicate the oil and gas industry’s response to shifting winds.

This briefing provides an overview of GEM’s 2025 Europe Gas Tracker data with a focus on hydrogen. These data reveal a hydrogen network that is still early in development, built on shaky foundations, and unlikely to decarbonize Europe’s economies as its developers promise.

The Europe Gas Tracker captures a wide slice of the hydrogen network

The January 2025 version of GEM’s Europe Gas Tracker offers one of the most comprehensive surveys of European hydrogen infrastructure being developed alongside the region’s methane gas network. The database includes the following types of projects, also shown in Figure 1:

• Twelve projects to import hydrogen derivatives, including liquefied hydrogen (LH₂), ammonia (NH₃), and synthetic LNG (eLNG), all associated with LNG terminals
• 323 new and retrofitted hydrogen-capable gas transmission pipeline projects totaling 50,165 km
• 96 gas-fired power projects with 44.6 gigawatts (GW) capacity for hydrogen-burning, associated with in-development gas plants

Figure 1

Hydrogen terminals, pipelines, and power plants would build on Europe’s existing gas network

Major European LNG import projects plan for a hydrogen future

Some of the major LNG import projects in Europe have begun planning to add or retrofit infrastructure to import hydrogen derivatives, including liquefied hydrogen (LH₂), ammonia (NH₃), and synthetic LNG (eLNG). Import projects for hydrogen derivatives are planned for long-operating facilities, such as Belgium’s Zeebrugge LNG Terminal, which envisions becoming the “Zeebrugge Multi-Molecule Hub,” as well as at new projects arising out of Europe’s gas crisis. Such projects include Brunsbüttel FSRU in Germany, which plans to import ammonia as early as 2026 and ultimately develop a facility to crack ammonia into hydrogen.

There are twelve hydrogen derivative import projects in GEM’s database, shown in Table 1 (see GEM.wiki for more project details). With six proposals, Germany is planning the most hydrogen derivative projects associated with LNG terminals, followed by France and the Netherlands, with two each. In most cases, details are sparse, with minimal information available on capacities, start years, and even the specific fuel types. Just three terminals have defined capacities, and five have set start years. Two-thirds of these hydrogen projects are actively in development, and the remaining third, at the bottom of Table 1, have simply stated that they may retrofit LNG facilities for hydrogen derivatives at some point in the future, with no definite plans in place on how or when they will proceed. Missing details around hydrogen derivative import projects are indicative of their tentative nature and the risk that they could lock in fossil fuel consumption if they move forward without credible plans to source hydrogen derivatives produced from renewable energy.

The most common hydrogen derivative in the list is ammonia, with seven projects planning to import it. Compared to LH₂, ammonia is easier to liquefy, has a higher energy density, and has a more established import and export industry. However, shipping ammonia to be cracked into hydrogen comes with its own challenges: ammonia is highly toxic, and the hydrogen cracking process is energy-intensive, reducing the fuel’s round-trip energy efficiency to 30–40%. And while green ammonia is more cost-effectively shipped than LH₂, it is still expensive compared to fossil-based ammonia or direct electrification.

Table 1

Although most of the LNG terminals associated with these projects are operating or in construction, the majority of the hydrogen derivatives projects are in early stages. None have entered construction or taken final investment decisions (FIDs) indicating they will move forward. Among the twelve in GEM’s data, seven have signed preliminary (typically non-binding) agreements among their sponsors to pursue the project, and three have issued calls for market interest.

Table 2

GEM’s data on hydrogen derivative terminals focuses on plans associated with existing LNG projects in the Global Gas Infrastructure Tracker database. There are other hydrogen infrastructure data resources — such as the Hydrogen and Production Infrastructure Projects Database from the IEA and the Hydrogen Infrastructure Map from a joint initiative in cooperation with the European Hydrogen Backbone — which include projects unaffiliated with existing LNG projects, as well as other types of hydrogen infrastructure, such as production and storage.

The proposed hydrogen pipeline network has grown more than 40% in a year

GEM has tallied 50,165 km of hydrogen pipeline projects in development in Europe. This proposed network has over 40% more pipeline by length than what GEM recorded in the 2024 Europe Gas Tracker report, and it is now equivalent to two-fifths of the length of the existing European gas transmission pipeline network. The leading countries planning to develop new hydrogen pipelines are Germany (9,154 km), Spain (6,020 km), and Bulgaria (4,476 km). A full breakdown of pipeline length in development by country, including how much of this development is supported by the European Commission’s 6th Projects of Common Interest (PCI) list, is shown in Table 3 for the top ten European countries.

Hydrogen pipeline projects are being organized by the European Hydrogen Backbone, an initiative involving 33 Transmission System Operators working in close coordination with the gas industry association Gas Infrastructure Europe. Pipeline projects have received significant public support through the most recent European Commission’s PCI list, which offers funding and streamlined permitting to projects totaling 22,394 km. It is worth noting that some hydrogen pipelines on the PCI list appear nearly identical to older gas pipeline projects that were proposed for PCI status or that made it onto previous PCI lists, suggesting that gas companies could be using the new hydrogen branding to garner support for these projects — which could carry methane gas if the green hydrogen economy fails to materialize at the massive scale envisioned. Revamped gas proposals include large, cross-border connections such as the H2Med Pipeline project (the newest iteration of the Midi-Catalonia Gas Pipeline) and the SoutH2 Pipeline (a slightly altered GALSI Pipeline), as well as a number of smaller, national projects.

Hydrogen pipeline projects are relatively split among those that purport to use new vs. retrofitted gas pipelines. In terms of length, about 30% each plan to use new hydrogen pipelines, retrofit existing gas pipelines, or use a mix of new and retrofitted pipelines. For the final 10%, plans are unknown. However, hydrogen can damage or leak from pipelines that are not designed for it, and retrofitting pipelines would largely entail replacing them.

The majority of pipeline projects, for which blending percentage is known, plan to be capable of transporting 100% hydrogen, or close to a full hydrogen blend. Merely 10% of projects by length state that they will use a 10% blend of hydrogen, whereas 36% of projects state they will carry about 100% hydrogen. There are 54% of projects by length that do not specify hydrogen blends.

Table 3

Finally, despite the coordination and support hydrogen pipeline projects have received from the European Hydrogen Backbone and European governments, development is still in early stages. Just one small hydrogen pipeline has entered construction, a segment of the Netherlands National Hydrogen Backbone (30 km) at the Port of Rotterdam.

Hydrogen-burning power projects remain largely immature

GEM’s data on hydrogen-burning power proposals finds that there are plans to implement 44.6 GW of such capacity at gas-fired power plants in development. These proposals include several categories of projects, and developers often do not provide enough information to differentiate which of these types is being planned: hydrogen blending into gas-fired power (i.e., less than 100% hydrogen), combusting 100% hydrogen, and “hydrogen-ready” gas-fired power plants that presumably can switch from gas to hydrogen in the future — sometimes without defined timelines or defined commitments to actually switch to 100% hydrogen. The lack of detail surrounding when these hydrogen-ready proposals will burn 100% hydrogen (and the lack of green hydrogen supply secured, shown in Figure 3) could allow for gas power projects to move forward without credible plans to reduce their emissions.

In terms of capacity, one-fifth of projects propose to burn 100% hydrogen, one-fifth would blend up to 50% hydrogen, and for over half of the hydrogen usage percentage is unknown. Only a quarter of hydrogen burning projects at gas plants researched by GEM indicated that they would use green hydrogen, while almost two-thirds did not specify what type of hydrogen would be used.

Hydrogen-blending power projects are being developed under the premise that blending cleanly-produced hydrogen can reduce power plants’ emissions, since hydrogen does not emit carbon dioxide when burned. Due to hydrogen’s low energy density, high levels of hydrogen blending are needed to reduce overall emissions. For instance, a 50% blend of hydrogen in a gas-fired power plant corresponds to only a 24% reduction in emissions. In order to blend high levels of hydrogen, these projects would require specific equipment modifications, because modern gas turbines are only capable of burning a blend of gas and up to about 20% hydrogen without overhaul.

The NGO Deutsche Umwelthilfe details other issues with hydrogen-based power plants, including that pure hydrogen turbines are not yet market-ready, and that planned projects are focused more on serving baseload rather than peaker needs, which would use limited green hydrogen resources inefficiently.

Two-thirds of these hydrogen-burning power proposals at in-development gas plants are concentrated in three countries: the United Kingdom (13.7 GW), Germany (13 GW), and Italy (4.1 GW), as shown in Figure 2. Germany’s hydrogen power plans center around “hydrogen-ready” power plants that promoters argue will eventually burn 100% hydrogen, although prominent projects have been delayed amid political turmoil.

Figure 2

More hydrogen-burning power proposals have advanced than hydrogen terminal or pipeline projects, but the sector is still immature. There are two projects under construction representing less than 2% of in-development hydrogen burning capacity tracked by GEM. There are six operating projects that are small pilot projects blending low percentages of hydrogen. Almost three-quarters of projects by capacity are still considered announced, the earliest phase. Only 15% of projects have planned start years before 2030, and more than half of projects do not have a start year specified. Finally, only a small fraction of projects have secured memoranda of understanding (MOU), contracts, or financing for hydrogen to supply their power facilities, shown below in Figure 3.

Figure 3

The emerging hydrogen network is a flawed decarbonization strategy

The EU envisions renewable hydrogen playing a significant role in decarbonizing the region’s economy by fulfilling 10% of its energy needs by 2050. Core EU policies such as the EU Hydrogen Strategy and REPowerEU set targets for renewable hydrogen production and imports and outline the sectors in which green hydrogen could play a role, including transport and industry. In particular, the most recent Projects of Common Interest and Mutual Interest (PCI/PMI) list adopted in November 2023 demonstrated the degree to which European policy has shifted, with as many as 65 of 166 projects related to hydrogen.

Hydrogen is a versatile fuel, and renewable hydrogen technically can be used in a wide range of applications including for steel and cement production; industrial heat; fuel for vehicles, trains, ships, and aircraft; producing biofuels and synthetic fuels; power generation; heating homes; and energy storage. Hydrogen has been described as a “swiss army knife” for its versatility, but, as an author at the think tank Information Technology and Innovation Foundation notes, it’s also a fitting descriptor because hydrogen is rarely the best tool for a given job. With respect to the infrastructure tracked by GEM — terminals, pipelines, and power plants — there are four significant drawbacks to building hydrogen projects atop the gas network.

First, retrofitting gas infrastructure to use hydrogen largely entails replacing it, so it is expensive and more difficult than often implied by project developers. Infrastructure that transports gas is not automatically suitable for hydrogen because of the differences in the gasses’ physical properties. Hydrogen can embrittle materials, and it is a smaller molecule prone to leaking, which is an issue given that it is an indirect greenhouse gas. Hydrogen requires colder temperatures than LNG to be liquefied, and LNG terminals are not easily converted to liquefying hydrogen or other hydrogen derivatives even if certain components may be repurposed.

Second, hydrogen is an inefficient means of transporting energy, and it is inefficiently burned for heating and power. Using renewable electricity directly is always more efficient than using it to generate hydrogen, as even high efficiency electrolyzers incur about 30% energy losses when splitting hydrogen out of water. For instance, the Environmental Defense Fund estimates heating homes with green hydrogen consumes seven times more energy than direct electrification. Transported by pipeline, hydrogen has a relatively low energy density compared to gas, which could present technical challenges for end uses originally designed for gas consumption.

Third, blending hydrogen into the gas network, which has been proposed as a decarbonization strategy, offers little in the way of emissions reductions. Technical constraints with the existing European gas grid limit blending to small amounts in existing infrastructure, often less than 10%. Because hydrogen has an energy density three times lower than that of gas, a blending percentage of 5%, for example, would only displace 1.6% of gas demand, according to the think tank E3G. Friends of the Earth Europe has noted that, “The EU’s own Hydrogen Strategy identified a number of issues with blending: it’s inefficient, it diminishes the value of hydrogen, it poses challenges to connecting networks across borders and for the design of the gas infrastructure.” With respect to blending hydrogen into gas-fired power plants, most new gas turbines can only blend up to about 20% hydrogen without overhauling the equipment; and again, because of hydrogen’s low energy density, this translates to a relatively small gas savings (e.g., 20% hydrogen blending enables only 7% reduction in gas consumption).

Fourth, and finally, there is a massive gap between expected renewable hydrogen production and the hydrogen needed to fuel a network of this scale. Only 0.3% of hydrogen produced today is green hydrogen. In its net-zero scenario, the IEA calls for 70 million tonnes per year (mtpa) of green hydrogen production capacity by 2030. Production projects totaling merely 3 mtpa had reached final investment decisions as of last spring, and Bloomberg New Energy Finance (BNEF) has estimated that around 16 mtpa in green hydrogen production might be achievable by 2030.

High projected costs of green hydrogen have been one factor depressing production and demand forecasts. The Energy Transitions Committee recently downgraded its global hydrogen requirements for 2050 from around 800 mtpa to 450 mtpa, noting that hydrogen remains expensive whereas the costs of clean electrification and battery storage are falling. A BNEF forecast in December 2024 tripled its prior 2050 cost estimate for the fuel, finding that green hydrogen was unlikely to become competitive with fossil-based hydrogen in most markets due to the high cost of electrolyzers.

The European Court of Auditors found that the European Commission’s targets for hydrogen production were unlikely to be met and “driven by political will rather than being based on robust analyses.” If new “hydrogen-capable” infrastructure comes online without green hydrogen to supply it, or without green hydrogen that is cost-competitive, this infrastructure could lock in fossil fuel consumption in Europe’s energy sector by using gas or fossil-based hydrogen instead.

How should green hydrogen be used?

Ideally, green hydrogen should be used close to where it is produced to avoid the challenges and costs associated with transporting it. It should be targeted for applications where it replaces existing fossil-generated hydrogen, such as ammonia production, and for sectors that cannot be decarbonized with electrification such as cargo shipping, long-haul aviation, and steelmaking. These so-called unavoidable uses are the highest priorities on the “hydrogen ladder.” The extensive hydrogen transportation network and hydrogen-capable power plants in planning in Europe fail to meet these criteria, and risk making poor use of limited green hydrogen supplies.

As hydrogen plans proliferate, new LNG proposals settle down

The planned buildout of hydrogen infrastructure follows on the heels of a rush to build new LNG import capacity, set off by Russia’s invasion of Ukraine. As shown in Figure 4, Europe’s LNG import capacity continues to grow as new projects come online, but the pace of new proposals has nearly ground to a halt, continuing a slowdown noted in last year’s Europe Gas Tracker report. In 2024, just one new LNG import terminal was proposed in Europe, Teesside WaveCrest LNG Terminal (8.2 billion cubic meters per year (bcm/y)) in the United Kingdom.

Figure 4

In 2024, Europe added a net 28.7 bcm/y in new LNG import capacity. Two new projects came online, Greece’s Alexandroupolis FSRU (5.5 bcm/y) and Germany’s Mukran FSRU (13.5 bcm/y), the latter of which required the FSRU vessel from the now-retired Lubmin FSRU project (5.2 bcm/y). In addition, this year, three capacity expansions were completed at Italy’s Toscana FSRU (+1.3 bcm/y), Belgium’s Zeebrugge LNG Terminal (+6.4 bcm/y), and Poland’s Świnoujście Polskie LNG Terminal (+2.1 bcm/y).

A further 23.3 bcm/y in new capacity reached FID this year, between Germany’s Stade LNG Terminal (13.3 bcm/y) and Brunsbüttel LNG Terminal (10 bcm/y). These onshore facilities are intended to replace two interim, floating projects: Stade FSRU (6 bcm/y), currently under construction, and the operating Brunsbüttel FSRU (5 bcm/y). Between the Stade and Brunsbüttel projects that reached FID and an additional 36.3 bcm/y in import capacity under construction, Europe will likely increase its total LNG import capacity by at least 11% by 2030, to a total of 375.8 bcm/y.

The field of proposed European LNG import projects remains large at 140.5 bcm/y, equivalent to two-fifths Europe’s operating capacity. However, these projects’ prospects become dimmer with each passing year as structural gas demand falls due to Europe’s climate policies and renewable energy installations.

Europe’s own energy watchdog, the EU Agency for the Cooperation of Energy Regulators (ACER), has said that LNG demand was likely to peak this year. The Institute for Energy Economics and Financial Analysis (IEEFA) has forecasted that Europe likely already reached peak LNG consumption and has found that half of the EU’s LNG terminals had capacity utilizations below 50% during the first half of 2024. Indicative of this overcapacity, the Lubmin FSRU and Mukran FSRU facilities at Germany’s Rügen island operated at a combined capacity of 8% in 2024, and the German government-owned operator of Wilhelmshaven FSRU shut down the facility for the 2024–25 winter season. “Germany’s costly LNG terminals aren’t paying off,” Bloomberg reported in January, as their high operating costs are a disincentive to using them for LNG imports.

Even if Europe faces a challenging year ahead refilling gas storage depleted by cold weather and the shutoff of Russian gas supplies through Ukraine, its capacity for LNG imports does not appear to be a constraint.

New LNG terminals already under construction in Europe are likely to exacerbate its overcapacity, and proposed terminals have become increasingly unnecessary.

Conclusion

With twelve import projects, 50,165 km in pipelines, and 44.6 gigawatts of power capacity in planning, the ways in which European countries propose building a hydrogen network atop their gas infrastructure are taking shape. Green hydrogen will be a limited, important resource for decarbonizing parts of the economy, but these plans risk using it in the wrong ways: transported over great distances and inefficiently burned for baseload power. Green hydrogen production is failing to take off as quickly as envisioned by Europe’s governments and organizations like the IEA, and a hydrogen-capable network of this scale could simply slow Europe’s transition away from gas, if it is ultimately used for gas or fossil-based hydrogen. European policy aimed at bolstering renewable hydrogen production; targeting it toward appropriate applications, such as replacing fossil-produced hydrogen in industrial applications; and ensuring gas infrastructure operators have realistic, concrete gas-to-hydrogen transition plans in place is more likely to aid the region’s energy transition and avoid locking in new fossil fuel consumption.

About the Europe Gas Tracker

The Europe Gas Tracker is an online database that identifies, maps, describes, and categorizes methane and hydrogen gas infrastructure in the European Union and surrounding nations, including gas pipelines, liquified natural gas (LNG) terminals, gas-fired power plants, and gas fields. Developed by Global Energy Monitor, the tracker uses footnoted wiki pages to document each project and is updated annually. The Europe Gas Tracker derives its data from GEM’s global trackers, namely, terminals and pipelines from the Global Gas Infrastructure Tracker, power plants from the Global Oil and Gas Power Tracker, and gas fields from the Global Oil and Gas Extraction Tracker.

About Global Energy Monitor

Global Energy Monitor (GEM) develops and shares information in support of the worldwide movement for clean energy. By studying the evolving international energy landscape and creating databases, reports, and interactive tools that enhance understanding, GEM seeks to build an open guide to the world’s energy system. Follow us at www.globalenergymonitor.org and on Twitter/X @GlobalEnergyMon.

Media Contact

Rob Rozansky

Project Manager & LNG Analyst

rob.rozansky@globalenergymonitor.com

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At the recent COP29 in Baku, funding mechanisms to support the green transition in developing countries fell short. Rich countries agreed to provide US$300 billion annually by 2035, up from an amount that some see as insufficient compared to the US$1.3 trillion per year requested. Meanwhile, the oil and gas industry continues to invest heavily in the continent as energy majors backtrack on green energy goals.

Across Africa, 39 midstream gas transmission pipeline projects are proposed and under construction at an estimated US$47.1 billion in capital expenditure costs, led by Mozambique, South Africa, and Nigeria. By length, this planned buildout is about 29,000 kilometers (km) of new pipelines, nearly one-quarter of the current length of electricity transmission lines across Africa.

Gas transmission infrastructure, including pipelines and liquefied natural gas (LNG) terminals, is an integral part of the gas value chain, and its development provides a litmus test for the health of the industry.

In sub-Saharan Africa, Nigeria and Mozambique epitomize major themes, hosting projects that represent the shifting interests of legacy oil and gas investors, as well as more recent newcomers. These plans face significant risk, including fluctuations in global gas demand, potential for civil unrest, and political instability at home. All this while the International Energy Agency (IEA) has projected global fossil fuel demand will peak by 2030, and Africa’s biggest export markets — Europe and Asia — are exhibiting declining and unpredictable gas demand.

If these trends are any indication, continued gas development is unlikely to bring the economic and energy development promised, and countries like Nigeria and Mozambique will remain vulnerable.

Nigeria

Nigeria, the world’s sixth largest LNG exporter, has enormous gas reserves, yet it is also home to the globe’s leading electricity access deficit.

Currently, the country is developing 3,700 km of gas transmission pipelines. While some of this development is planned to address the domestic electrification deficit, the bulk is intended for exporting gas via pipeline or LNG terminals.

But this planned buildout is occurring in an industry that has stalled over the past two decades. Since 2008, two national gas initiatives have been released by the government to provide gas-fired power and development in Nigeria — and both have largely failed.

For example, the Ibadan–Jebba Gas Pipeline, a proposed 510-km network designed to expand gas access across Nigeria’s western and central states, has remained only a proposal since 2017. Similarly, the Trans Nigeria Gas Pipeline, aimed at connecting pipeline networks across Nigeria, has progressed slowly, though its first phase — the Ajaokuta–Kaduna–Kano (AKK) Pipeline — is nearing completion and is hailed as a critical driver for economic growth and industrialization.

The most ambitious projects, however, carry the goal of gas export to Europe and Asia. Two competing proposals, the Trans-Sahara Gas Pipeline and the Nigeria–Libya Gas Pipeline, would transport gas from Nigerian extraction areas to North Africa and onward to Europe. Meanwhile, the Nigeria–Morocco Gas Pipeline has recently entered the land acquisition phase, with plans to supply gas to thirteen countries en route to Spain. The Gulf of Guinea Gas Pipeline will carry gas from the Nigerian coast to Bioko Island, where it will be processed for LNG export at the Punta Europa LNG Terminal.

These projects rely on broader forces driving oil and gas development, particularly in extraction areas. But onshore production in the Niger Delta is declining, and foreign developers like Shell are moving offshore to the Gulf of Guinea, leaving decades of environmental degradation and corporate accountability issues behind.

While France and the United States continue to maintain a significant investment presence in Nigeria, newer players like China and India are increasingly investing in African fossil fuels, driven by their own energy security needs and strategic partnerships through projects like the Belt and Road Initiative. Chinese banks, for example, are reported to have funded 85% of the US$2.8 billion AKK Pipeline, and CNOOC holds a stake in two offshore fields.

Mozambique

Mozambique exemplifies the volatile intersection of gas development and civil unrest in Africa. The country holds significant gas resources in the Rovuma Basin, offshore from Cabo Delgado province, but since 2017, an Islamic insurgency has disrupted stability and development in the region, partly fueled by local grievances over the lack of benefits from the exploited gas.

The Rovuma LNG Terminal and Mozambique LNG Terminal, along with a small related pipeline, are key export projects that have faced delays due to the ongoing insurgency, and a recently contested presidential election threatens to worsen this situation. Additionally, two competing pipelines are proposed to transport gas from production from these offshore resources to neighboring South Africa.

The African Renaissance Pipeline, which would be 2,600 km in length, is a joint venture among Mozambican, South African, and Chinese state-owned enterprises. But the project is several years behind schedule and remains in limbo, highlighting the faltering and increasingly unappealing nature of these ambitious export routes to South African importers. The alternative GasNosu Pipeline has met a similar fate.

To Mozambique’s north, the proposed Tanzania–Kenya Gas Pipeline aims to link Cabo Delgado’s transmission network to Mombasa, Kenya, promising energy independence. However, as with many major pipelines in Africa, progress is plagued by slow development and financial hurdles.
The continued development of upstream resources offshore Cabo Delgado, combined with sluggish but persistent pipeline development in Mozambique, highlights how gas exports are being prioritized at the expense of gas electrification domestically. And, similar to Nigeria, China and India are investing substantially in Mozambique’s oil and gas resources.

The future of gas in two African hotspots

In both Nigeria and Mozambique, decades of oil and gas development spurred by Western corporations have largely failed to benefit locals, either through foreign direct investment or by providing domestic access to fossil resources. Instead, these projects have encroached on farmland, impacted ecosystems, and fueled theft and civil disorder.

As legacy investors shift priorities, they benefit from weaknesses in local regulatory and compliance processes, leaving African nations burdened with the negative externalities of these developments. Yet major pipeline projects continue to receive backing from African heads of state, and these pipelines are being developed on timelines that coincide with a global peak in gas demand — a critical inflection point.

While the goals of electrifying and industrializing are key, the case for achieving these aims with renewables, instead of gas, is compelling. Africa is rich in renewable resources that can be deployed on decentralized grids, which would make electricity cheaper as a result.

In contrast, gas electrification relies on centralized networks and geopolitics, and it depends on capital-intensive pipelines, distribution, and storage — none of which are widespread in sub-Saharan Africa, making it more expensive. Relying on gas also exposes countries to global price volatility and geopolitical risks. If Africa continues with current gas infrastructure plans, it could face billions in stranded assets and be left to manage a far costlier environmental and financial burden.

About the Global Gas Infrastructure Tracker

GGIT is an information resource on natural gas transmission pipeline projects and liquefied natural gas (LNG) import and export terminals. The internal GGIT database and wiki pages are updated continuously throughout the year, and an annual release is published and distributed with data summary tables. The data are released under a creative commons license and can be downloaded here.

What is Global Energy Monitor?

Global Energy Monitor (GEM) develops and shares information in support of the worldwide movement for clean energy. By studying the evolving international energy landscape and creating databases, reports, and interactive tools that enhance understanding, GEM seeks to build an open guide to the world’s energy system. Follow us at www.globalenergymonitor.org and on Twitter/X @GlobalEnergyMon.

Media Contact

Baird Langenbrunner

Project Manager, Global Gas Infrastructure Tracker and Global Oil Infrastructure Tracker

baird.langenbrunner@globalenergymonitor.org

The post Nigeria and Mozambique’s gas buildout: A case of false promises appeared first on Global Energy Monitor.

• As of 2024, an estimated US$1.1 trillion of new liquefied natural gas (LNG) terminals are in development, up 6% from last year, despite repeated calls from the International Energy Agency (IEA) for the LNG trade to peak this decade in order to limit global warming to 1.5℃. There are 1,048.2 million tonnes per annum (mtpa) of LNG export capacity and 672.7 mtpa of LNG import capacity in development. New LNG projects that are under construction or are proposed risk becoming stranded assets in the energy transition.

• Mexico and Argentina have proposed significant LNG export capacity additions that could make Latin America and the Caribbean (LAC) a major exporting region, though these projects face barriers. Mexico’s proposed LNG export terminal buildout, which relies in large part on U.S. gas from the Permian Basin, is estimated to cost US$54.3 billion and is the third-largest slate of such projects in the world, with a total capacity of 73.6 mtpa. Argentina is planning one of the largest export facilities ever considered, the 30 mtpa Argentina GNL Terminal, which would draw on the Vaca Muerta shale basin and contribute to environmental injustices associated with its extraction.

• LNG import terminals in development across the LAC region could cost US$7.2 billion and add up to 46 mtpa in new import capacity, which would boost existing capacity in the region by half. Brazil has the fourth-largest buildout of LNG import terminals in development globally at 36.5 mtpa.

• New LNG terminals also depend on or lead to the development of other massive gas infrastructure projects, such as pipelines and gas-fired power plants, which come with their own emissions, human health, and socio-ecological impacts. LNG terminals currently under development are connected to projects building 2,652 kilometers (km) in new gas transmission pipelines and 19.3 gigawatts (GW) in new gas-fired power capacity.

• New LNG import infrastructure risks locking the LAC region into further gas dependence for decades. Compared to increasing imports of foreign gas, countries’ ambitious renewable energy plans offer a more economically and environmentally sustainable path forward.

Introduction

In 2024, Latin America and the Caribbean’s plans for new LNG terminals assumed greater significance on the global stage — and continued to risk derailing the region’s energy transition. Planned LNG export and import terminals in the region total an estimated US$123.6 billion in new investments, much of which are concentrated in three countries: Mexico, Argentina, and Brazil. 

In January, the U.S. government issued a pause on authorizing proposed LNG terminals to export U.S. gas to non-Free Trade Agreement (FTA) countries, a de facto permitting freeze on over a dozen U.S. projects, as the Department of Energy reevaluated whether such projects are in the public interest. While the policy’s future is now uncertain amid defeat in court and an upcoming election, the prospect of U.S. policy turning against new LNG exports has cast a spotlight on alternatives around the world. Mexico, in particular, has garnered attention as another outlet for U.S. gas to reach international markets, and its existing plans comprise the third-largest planned LNG export buildout in the world, totaling 73.6 mtpa (Figure 2). The majority of this capacity is not guaranteed to come online, especially given various permitting and financing barriers, but in 2024, Mexico launched its first LNG export terminal. 

Meanwhile, Argentina advanced this year toward developing its first LNG export terminal, the massive 30 mtpa Argentina GNL Terminal, which would be one of the largest projects ever built. The terminal would export gas from the Vaca Muerta shale basin, which has long been an Argentinian national objective. The basin’s extraction has also been fraught with environ mental justice issues, and it has been described as a global “carbon bomb.”

At the same time, a fleet of import terminals proposed across the region, with half as much capacity in development as currently operating, could increase the region’s dependency on gas imports. In particular, Brazil has planned the fourth-largest buildout of LNG import terminals globally at 36.5 mtpa (Figure 2), and it brought online three new import projects just this year.

Many new LNG terminals would require or entail the construction of other gas infrastructure, such as pipelines and gas-fired power plants. These projects would involve even greater investments and come with their own emissions, human health, and socio-ecological impacts. According to GEM data, LNG terminals currently under development are connected to projects building 2,652 km in new gas transmission pipelines and 19.3 GW in new gas-fired power capacity. An additional 7.5 GW of gas-fired power capacity is under development to accept LNG from Brazilian import terminals that have come online since 2020. A list of these projects is shown in Appendix Table A5.

All of these expansions to the LAC region’s role in the LNG economy are being planned despite the IEA’s warning that the global LNG trade should peak in the middle of this decade for the world to meet its climate goal of limiting global warming to 1.5℃. New LNG export projects have a high likelihood of becoming stranded assets if countries meet their own climate objectives, and recent geopolitical events, including the war in Ukraine, have demonstrated the volatility and unreliability of LNG imports. 

The LAC region’s LNG buildout faces significant barriers and is by no means certain to advance. Given the region’s abundant renewable resources and its progress planning new renewable energy projects, LAC could avoid sinking investment into the global LNG boom and focus on developing clean energy.

This briefing provides an overview of LNG development in the LAC region, focused on Mexico, Argentina, and Brazil, drawing on September 2024 data from Global Energy Monitor’s (GEM) Global Gas Infrastructure Tracker (GGIT). Data on multiple types of energy infrastructure across LAC can also be found in GEM’s Latin America Energy Portal.

Figure 1

LNG terminals by the numbers: 2024 GGIT update

*This figure includes in-construction projects that were not completed by GEM’s data update in September 2024 but are scheduled to come online by the end of the year.^†Percent changes are in terms of capacity in development, with respect to GEM’s October 2023 GGIT data.

Figure 2

For more global LNG data, see the Appendix tables and GEM’s online resources for the GGIT including a tracker map, summary tables, dashboard, and data download.

Mexico’s LNG buildout would export U.S. gas, but projects face barriers

Mexico has the world’s third-largest set of LNG export projects planned, with 73.6 mtpa in export capacity proposed or in construction (Figures 2 and 3). The country’s sizable plans are notable in part because Mexico did not have any operating LNG export terminals until this year. In addition, the Biden Administration’s pause on LNG export authorizations has renewed attention on Mexico as an alternative pathway to export U.S. gas from the Permian Basin, although such projects are subject to the same U.S. policy.

In August 2024, Mexico’s first LNG export terminal began operations, the 1.4 mtpa Train 1 of New Fortress Altamira FLNG Terminal. In July 2024, owner New Fortress (NFE) reported that it had closed on a $700 million loan to finance Train 2, which is reportedly under construction and scheduled for commissioning in Q1 2026. NFE reports that it has a non-binding MOU with the Mexican government to construct up to three additional 1.4 mtpa trains, but details are sparse.

Just one other export facility is under construction in Mexico, Costa Azul LNG Terminal. Train 1 of this terminal (capacity 3.25 mtpa) is under construction and reportedly 85% complete as of August 2024. Until recently, commercial operations were expected in 2025, but labor and productivity challenges have now pushed commissioning back to Q1 2026, close to the U.S. Department of Energy’s March 29, 2026 “export commencement” deadline. The much larger Train 2 (12 mtpa) is still “under development,” according to Sempra’s most recent quarterly report (August 2024).

Mexico’s most ambitious proposal is Saguaro Energía LNG Terminal, which comprises three to six trains with a total capacity of 15–30 mtpa, making it among the largest projects under consideration globally (Table 1). Owner Mexico Pacific Ltd (MPL) has already signed nine contracts with seven Asian-Pacific customers to supply 14.1 mtpa of LNG over the next 20 years. However, the company has repeatedly delayed a final investment decision (FID), most recently until 2025. The terminal’s gas supply will be contingent on construction of the 250-km Saguaro Connector Pipeline in the U.S. and the 800-km Sierra Madre Gas Pipeline in Mexico, with anticipated start-up dates no earlier than 2027 and 2028, respectively. Mexico Pacific’s current export agreement with the U.S. Department of Energy expires in December 2025, meaning that an extension will be necessary to get the project off the ground.

Broadly, Mexico’s LNG buildout faces barriers that could significantly limit how much new capacity will be built. Complicated permitting processes with long wait times have challenged developers, in large part due to the Mexican government reducing permitting staff and prioritizing public over private permits, but also exacerbated by the U.S. LNG pause. New pipelines are required for several projects, including — as mentioned above — the Saguaro Energía terminal, and its proposed Saguaro Connector Pipeline (Appendix Table A5), which is facing legal challenges brought by consumer and environmental advocates. There are also concerns in Mexico about securing enough gas for domestic use. Mexico relies on the U.S. for most of its gas supply, and there is a risk that the U.S. could curtail piped gas to Mexico, as it did during a 2021 winter storm, or as it might do under the policies of an “America First” Trump presidency. BNamericas has reported that, amid these issues, “financiers are getting cold feet and developers are delaying final investment decisions.” Columbia’s Center on Global Energy Policy has said, “Most of these [Mexican LNG] projects are unlikely to be built due to financial constraints, among other challenges.”

Like LNG projects on the U.S. Gulf Coast, many proposed Mexican LNG projects pose environmental and environmental justice threats. These export terminals could harm low-income and marginalized communities in Mexico already suffering from industrial pollution, and many projects have not obtained a social license from local communities or Indigenous peoples. Shortly after the U.S. LNG pause, Greenpeace Mexico and others petitioned the Mexican government to follow suit and block its projects given their health, environmental, and climate impacts. The organization has also called attention to the impacts of Mexico’s biggest planned project, Saguaro Energía LNG Terminal, on whales and other marine life in the Gulf of California. Just as Mexico’s projects are an extension of the U.S. LNG buildout, they risk exporting the harm of U.S. fossil fuel activities into the communities and environments of Mexico.

Figure 3

Argentina’s LNG megaproject would enable extraction of the Vaca Muerta

Argentina has the world’s eighth-largest planned buildout of new LNG export capacity (Figure 3), primarily due to the US$30 billion Argentina GNL Terminal proposed by Argentina’s YPF and Malaysia’s Petronas (although the latter recently indicated it may exit the project). In August of this year, the project advanced as its sponsors reached agreement on siting the new LNG export terminal at Punta Colorada, near the municipality of Sierra Grande in Río Negro province, with a FID expected in 2025. If developed as planned, the Argentina GNL megaproject would involve construction of three new pipelines and a terminal built in three phases to a total capacity of up to 30 mtpa, easily the largest LNG export project in the LAC region and among the largest in development globally (Table 1).¹

The Argentina GNL Terminal would export gas from the Vaca Muerta formation in Neuquén province, the world’s second-largest shale gas deposit. Exploiting this resource has been a longtime national objective. Production at Vaca Muerta started more than a decade ago, but gas distribution was limited by insufficient transmission infrastructure, forcing Argentina to rely on seasonal LNG imports during the winter months through the Bahía Blanca GasPort FSRU and Escobar FSRU import terminals. In July 2023, everything changed with the commissioning of the 573-km, 21 million cubic meters per day Néstor Kirchner Gas Pipeline, which has relieved bottlenecks and set off a chain reaction of new pipeline construction designed to bring Vaca Muerta gas to Buenos Aires and beyond.

Fracking and exporting gas from the Vaca Muerta shale basin is controversial because of environmental justice and climate impacts. Indigenous communities have seen their territories licensed for new developments despite opposition. Communities in the vicinity of fossil fuel activities have “faced a lack of access to potable water; increases in health problems […]; and pervasive toxic remnants of extraction in the form of open-air pits and landfills,” and extraction work threatens the livelihoods of locals such as farmers. A significant share of the profits from the gas field development go to foreign companies, and projects have not brought benefits to local people as promised by the authorities. The impacts of extraction activities on people and environments also extend well beyond the shale basin, with existing and planned fossil fuel projects, such as pipelines, sprawling across Argentina and into neighboring countries. Finally, the resource has also been described by environmentalists as a “carbon bomb,” one that could eat up 11% of the world’s carbon budget to limit warming to 1.5℃.

Table 1

A few smaller LNG export projects are being pursued in Argentina as well. In July 2024, Golar and Pan American Energy announced that they had signed a 20-year agreement for the Golar-Pan American FLNG Terminal with a capacity of 2.45 mtpa and a 2027 start-up date. In the same month, Argentine gas pipeline operator TGS confirmed that it was also studying the possible development of a 4–5.3 mtpa LNG export terminal, TGS Puerto Galván LNG Terminal, at Puerto Galván in Bahía Blanca, Buenos Aires province.

Figure 4

Brazil plans one of the world’s largest LNG import expansions

Brazil is the largest LNG importer in the LAC region, and it has planned the world’s fourth-largest buildout of LNG import capacity, totaling 36.5 mtpa (Figures 2 and 4). The country relies on imports for approximately 40% of its gas supply. Historically, most imported gas came from Bolivia, but production declines have prompted Brazil to consider fracked gas from Argentina and imported LNG as alternatives. Additionally, while hydropower can provide most of Brazil’s electricity, unreliable generation during droughts in recent years has pushed Brazil toward developing LNG import capacity.

Prior to 2020, Brazil only had three LNG terminals — Pecém FSRU, Guanabara Bay FSRU, and Bahia FSRU — with a total import capacity of 17.5 mtpa. However, the country’s LNG import capacity has more than doubled over the past five years (Figure 5). Two new import terminals, New Fortress Barcarena FSRU and Terminal Gás Sul FSRU (each with a capacity of 6 mtpa), began commercial operations in the first quarter of 2024, joining a wave that began in 2020 and 2021 with the commissioning of the Sergipe FSRU and Porto do Açu FSRU terminals (5.6 mtpa each) and the 2.7 mtpa Sepetiba Bay FSRU in 2022. Two other new terminals (Cosan FSRU and Suape FSRU) will come online in 2024 or 2025.

Figure 5

The surge of new LNG terminals has coincided with development of several large new gas plants, including Porto de Sergipe power station (1.6 GW), GNA I power station (1.3 GW), GNA II power station (1.7 GW), and Novo Tempo Barcarena power station (2.2 GW). Several additional LNG import terminals remain on the drawing board, including the Tepor Macaé FSRU, Porto Norte Fluminense FSRU, Presidente Kennedy FSRU, Itaqui FSRU, Geramar FSRU, São Marcos Bay FSRU, Dislub Maranhão FSRU, and Nimofast Antonina LNG Terminal.

Other LAC countries plan one-fifth of region’s LNG import projects

Beyond Brazil, smaller economies in LAC are developing 9.4 mtpa in LNG import capacity, about one-fifth of such capacity planned across the region (Figure 4). In October 2023, the Chilean Council of Ministers revived the shelved 2.7 mtpa Penco Lirquén FSRU, granting it an environmental permit nine years after it was first proposed. The project is planned to start operating in 2027, though it faces legal challenges from local communities concerned about impacts on marine life. In Nicaragua, New Fortress is constructing the 1.3 mtpa Puerto Sandino FSRU, which is set to begin operations in Q4 2024, though it has suffered repeated delays, partly due to the threat of U.S. government sanctions against the country. Colombia has the second-most LNG import capacity in development regionally, 4.1 mtpa, though its projects such as the proposed Buenaventura FSRU have struggled to attract investors.

LAC has a safer path forward than LNG

Doubling down on LNG imports could be a risky path forward for LAC countries. Recent geopolitical events, notably the war in Ukraine, have demonstrated the volatility of the global gas market — in 2022, gas prices were 40% higher in Argentina, Brazil, and Uruguay. Latin America and the Caribbean also felt the impacts of this energy shock through the price of fertilizer, tightly linked to the cost of gas, which was almost 190% higher in the first half of 2022 compared to that period of the prior year.

Moreover, there is a risk that investments in new LNG terminals across the region — totaling an estimated US$123.6 billion — could be underutilized in the energy transition and ultimately waste public and private resources. The IEA, in its conservative Stated Policies Scenario (STEPS), has said that most new electricity generation in the region will be provided by solar and wind power and noted that if domestic gas production increases, it could limit the use of gas import infrastructure. The organization has also noted that, under various scenarios, LNG exporters in the LAC region “face the risk that new projects are not cost-competitive or result in stranded assets.” As recently as the start of this year, Energy Intelligence forecasted that South American LNG imports were expected to be down in 2024, “as a gloomy economic outlook and renewable power sources are expected to eat into natural gas demand looking forward.”

LAC has a safer path forward: fast-tracking its energy transition and focusing investments on clean power, while avoiding fossil fuel market volatility and stranded asset risks. Renewable energy sources, including mega-hydropower projects, already provide 60% of the region’s electricity, and even as hydropower has faltered in Brazil this year due to drought, generation has been primarily replaced by solar and wind. In the 2023 Race to the Top report on solar and wind development in Latin America and the Caribbean, GEM found that the region is “on track to meet, and potentially surpass, [IEA] 2030 regional net zero renewable energy goals if it implements all of its prospective larger-scale projects.”

Conclusion

New LNG infrastructure in Latin America and the Caribbean could alter the region’s energy sector and its role in global gas markets, though a large LNG buildout is by no means certain. On the export side, massive investments in new terminals are a great risk in the energy transition. And on the import side, renewable energy paired with storage represents a more sustainable path forward. With abundant solar and wind resources and a strong slate of renewable projects already in development, the LAC region is well-positioned to sidestep the global LNG boom and build quickly toward a clean energy future.

¹ The Argentina GNL Terminal project is the third-largest LNG export terminal in development anywhere around the world if developed to its maximum proposed capacity of 30.2 mtpa (Table 1), and it would be the biggest investment in Argentine history.

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According to data researched by Global Energy Monitor,¹ the top three leading gas turbine manufacturers — GE Vernova, Siemens Energy, and Mitsubishi Power — dominate the global gas turbine market for gas-fired power plants under construction, with two-thirds of the market. GE Vernova leads the global market with almost 55 gigawatts (GW) of turbines under construction. 

But a business model that relies on the continued buildout and maintenance of gas plants as well as the provision of service contracts relies on shaky foundations. The rapid expansion of partnerships by leading manufacturers, coupled with heavy investments in unproven hydrogen technology, may expose these market players to geopolitical and financial risks, as looming global gas power overcapacity and the clean energy transition gather pace.

Leading regional trends among turbine manufacturers

The company GE Vernova has focused heavily on Asia, where more than two-thirds of the world’s gas-fired capacity under construction is located. GE Vernova² dominates this region with 38% of Asia’s gas turbine market under construction, followed by Mitsubishi³ with 17%, and then Siemens Energy at 16%, according to GEM data.

China has the largest share of gas-fired capacity in development within the Asia region,⁴ 151 GW, and approximately 46 GW under construction.

Strategic partnerships expose manufacturers to broader geopolitical risks

Leading turbine manufacturers have focused partnership development efforts in China, due to its large gas power market. GE Vernova provides 39% of gas turbines for in-construction gas plants in China — either directly, or through its joint venture, Harbin Electric General⁵. Dongfang Electric Corporation⁶, Mitsubishi’s joint venture in China, accounts for nearly 25% of gas turbines in construction in China. While Siemens Energy does not have a joint venture in China, it signed an MOU in 2018 with China’s State Power Investment Corporation (SPIC) in 2018, followed by a strategic partnership agreement in 2019 to support technology cooperation with a goal of SPIC developing its own heavy-duty gas turbines.

Other notable partnerships include GE Saudi Advanced Turbines (GESAT), a joint investment between GE Vernova and Dussur, the first facility in Saudi Arabia and the region to manufacture H-Class gas turbines and components. GESAT recently rolled out its first H-class gas turbine manufactured at its Saudi Arabia facility, and GE Vernova also announced its largest order in the Middle East and North Africa region to date — eight turbines as well as a 21-year service contract agreement. 

While these partnerships have helped turbine manufacturers expand market presence and enhance technological capabilities in key regions, they have also exposed these companies to broader geopolitical risk.

For example, in 2011, Siemens Energy formed a joint venture, Siemens Industrial Turbomachinery, with a Russia-based company called Power Machines but had to subsequently sell its 65% stake to local Russian state company InterRAO in 2022. Additionally, GE Vernova was forced to abandon its joint venture with Russia-based InterRao in 2023. GE even noted in its 2023 Annual Report that its “RPO [was]…partially offset by decreases due to the impact of expanded sanctions on Gas Power contractual services in Russia.” More recently, in July 2024, Germany’s government blocked the sale of MAN Energy’s gas turbine business to China-based CSIC Longjiang GH Gas Turbine Co., citing national energy concerns.

Hydrogen is a false solution to gas power

Leading gas turbine manufacturers have focused their research on developing advanced turbines that can support flexible power generation and are capable of burning hydrogen. In the last few years, corporations have increasingly been justifying the construction of new gas-fired power plants by suggesting that these “hydrogen ready” gas plants could be converted to using hydrogen at a future date.

However, lack of hydrogen supply, pipeline infrastructure, and storage capacity for hydrogen are significant and costly barriers to overcome, as detailed in a recent Institute for Energy Economics and Financial Analysis (IEEFA) report. Currently only 1% of the world’s hydrogen is derived from renewable sources, and the costs of this green hydrogen have been rising. Due to its lower energy content, even using green hydrogen in power production provides little CO₂ emissions benefit until it is blended at high levels. For example, a 30% hydrogen blend by volume achieves a 12% reduction in CO₂ emissions and a 75% hydrogen blend only reaches a 50% emissions decrease. Moreover, blending high levels of green hydrogen consumes large amounts of renewable energy that would more efficiently be used to directly replace existing fossil fuel generation. 

According to GEM data, 47%, or approximately 82 GW, of turbines in gas-fired plants under construction are capable of blending 50% hydrogen. Top turbine models include GE Vernova’s 9HA turbine, which makes up 20 GW of turbines under construction.

As the speed and scale of the energy transition accelerate, turbine manufacturers’ profits hinge on risky forecasts and uncertain asset utilization

GE Vernova, Siemens, and Mitsubishi all posted record Q2 2024 profits driven by strong gas turbine sales. However, only six years ago, prospects were looking grim — manufacturers failed to see the growth of renewables and were faced with a steep decline in gas turbine sales. GE Power’s profits fell 45% in 2017, and its shares plunged. GE and Siemens both cut thousands of jobs. Siemens considered selling its gas turbine business or merging the unit with Mitsubishi. These events show how quickly investments can erode in a rapidly evolving energy landscape.

If history is any indication, during this time of record-setting renewable generation and falling gas share in the energy mix, turbine manufacturers could once again be misreading the speed and depth of the energy transition and these continued gas investments. These investments contravene corporate climate targets⁷ and will become underutilized stranded assets, exposing manufacturers to large financial risks.

GE states optimistically in its most recent annual report that it  “…expect[s] the gas power market to remain stable over the next decade with gas power generation continuing to grow [in the] low single digits.” However, the International Energy Agency (IEA) is projecting that fossil fuel demand will peak by 2030, and there are already signs of a rapid shift. Wind and solar generation overtook fossil fuel generation for the first time in the EU in the first half of 2024, even as energy demand rebounded. In fact, data is pointing to renewables replacing gas-fired generation in Europe, as gas-fired generation hit a two-decade low for 2024 thus far. In China, the growth of renewables has displaced coal generation. Renewables capacity buildout is booming, and China is on track to meet its 2030 energy target six years early. 

The incentive for manufacturers extends beyond securing initial turbine orders — locking in more lucrative long-term service agreements and equipment upgrades or servicing of existing gas plants provides a steady revenue stream after equipment has been sold. GE has approximately 1,700 gas turbine units under long-term service agreements with an average remaining contract life of ten years, and services make up 70% of GE’s revenue. Thus, revenues from long-term service contracts are heavily dependent on the utilization of an asset,⁸ making underutilized gas plants a risk. 

This is not the first time turbine manufacturers have misread the market. In 2017, GE Power Services was responsible for 98% of GE Power’s reported profits and all its operating cash flows. But its reported profits were a result of GE’s reductions in estimates for the cost to complete its multi-year service contracts, such as providing repairs and services to turbines.  Since GE had failed⁹ to see the market decline, they used alternative accounting methods — altering assumptions of costs required to fulfill their service contracts — in order to meet financial targets. As renewables continue to gain market share, gas turbine utilization rates will presumably continue to decline, posing new threats to turbine manufacturers’ bottom lines.  

Gas turbine manufacturers are gambling on gas power remaining a significant part of the future energy mix by continuing to develop partnerships and invest in hydrogen technology. As the threat of gas overcapacity and geopolitical risks rise, a swiftly transforming energy transition may once again upend this bet.

¹Methodology: Gas turbine manufacturer and model data was collected for projects in pre-construction and construction status with technologies of gas turbine or combined cycle. Unavailable data accounted for 17% of construction plants and 69% of pre-construction plants.

²GE Vernova or its joint ventures, Harbin Electric General and GE Saudi Advanced Turbines.

³Mitsubishi or its joint venture, Dongfang Electric Corporation

⁴Projects in announced, pre-construction, or construction status using gas turbine or combined cycle technology.

⁵ In 2017, the companies entered a strategic partnership to build a gas turbine manufacturing joint venture in Qinhuangdao.

⁶In 2004, the companies formed a joint venture to build a gas turbine factory in Guangzhou. This partnership was bolstered by an MOU signed in 2018 to bring Mitsubishi’s latest J-series gas turbine to Sichuan province.

⁷GE Vernova has committed to net zero carbon emissions by 2050. Siemens aims to have a net zero carbon footprint by 2030. Mitsubishi aims to achieve net zero carbon emissions by 2040.

⁸ “Customers generally pay us based on the utilization of the asset (per hour of usage for example) or upon the occurrence of a major event within the contract such as an overhaul or major outage. As a result, a significant estimate in determining expected revenues of a contract is estimating how customers will utilize their assets over the term of the agreement. The estimate of utilization, which can change over the contract life, impacts both the amount of customer payments we expect to receive and our estimate of future contract costs. Customers’ asset utilization will influence the timing and extent of overhauls and other service events over the life of the contract.” GE 2023 Annual Report

⁹“GE Power Services acknowledged internally that it had increased risk that its service agreements would need to be renegotiated due to lower than anticipated power consumption and increasing competition from other companies that offered servicing and repair of the power turbines after GE Power had sold them to customers. The business also faced the prospect that customers would exercise termination clauses in the service agreements if they did not receive price and terms concessions from GE Power, which created further risk to GE Power Services.” SEC Order

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• Gas expansion plans could lead to a doubling of Southeast Asia’s gas-fired power capacity and an 80% increase in liquefied natural gas (LNG) import capacity at a cost of US$220 billion. 
• Vietnam, the Philippines, Indonesia, Malaysia, and Thailand are at the forefront of this push.
• Renewables can help cover the gap: Utility-scale solar and wind projects that are already planned would match nearly two-thirds of the projected energy demand increase for 2030.

A massive expansion of gas-fired power and LNG import and export capacity is planned for Southeast Asia that if built could lock the region into an economically-volatile and insecure fuel and draw investment away from the energy transition, according to a new report from Global Energy Monitor.

Data in the Asia Gas Tracker show over 100 gigawatts (GW) of gas power capacity in development — projects that have been announced or are in the pre-construction and construction phases — together with 47 million tonnes per annum (mtpa) of LNG import capacity and 16.7 mtpa of export capacity.

International finance is incentivizing the development of gas infrastructure via mechanisms like the Just Energy Transition Partnerships and bilateral investment, particularly from Japan. Yet Southeast Asia could meet its growing energy needs through renewable sources, which are increasingly cost-competitive. If redirected, international finance could instead support the development of solar and wind projects and the stability of the regional power grid.

Data in Global Energy Monitor’s Global Solar Power Tracker and Global Wind Power Tracker show that the region’s prospective large utility-scale solar and wind capacity, if successfully built, can generate 450 terawatt hours annually of electricity, which equates to almost two-thirds of electricity demand projected by 2030.

Energy demand is increasing across Southeast Asia as economies grow, but ramping up gas production is not a long-term solution. Meeting demand with cost-effective, renewable sources insulates the region from volatile gas prices and is a greener path forward.

Warda Ajaz, Project Manager for the Asia Gas Tracker

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Perhaps by leveraging nostalgia, Putin hoped to persuade Xi of the merits of Power of Siberia 2, the high-profile gas pipeline that would be the third in a series of such projects designed to deepen the links between the two countries’ energy systems.

But Beijing is right to remain sceptical of the project, which presents costly economic and political risks to China’s interests as it aims to maintain its energy security and follow through on its energy transition.

Earlier this year, construction started on the second pipeline, the China-Russia Far East Pipeline, which will complement the first, called the Power of Siberia. The Power of Siberia has yet to be completed and is not operating at full capacity.

If all proceeds as planned, the three pipelines will eventually deliver 98 billion cubic metres of gas every year to China, equivalent to Russia’s total gas exports via pipeline last year and a quarter of China’s total gas consumption that year.

But such a deepening of dependence on Russia would cut against China’s energy security strategy. China, which imports 42 per cent of its gas supply, has made efforts over the last two decades to diversify its energy imports to reduce its dependency on any one source.

Three pipelines now source gas from Turkmenistan, Uzbekistan and Kazakhstan. In the southwest, China constructed the Sino-Myanmar pipeline, and on its southeastern coast, China has developed a cluster of liquefied natural gas (LNG) terminals that can receive imports from more than 20 countries, with Qatar and Australia the top suppliers last year.

These efforts show how China is striving to achieve a balanced and diverse energy mix. But if two more pipelines from Russia are added, a third of China’s total gas consumption when counting LNG will be from one country.

Power of Siberia 2 is also a costly proposition for China. Even as Russia has offered bargain basement gas prices to incentivise the development of the project, China would need to construct several hundred kilometres of gas pipelines through the desert to connect the project to the main demand centre, the Bohai Economic Rim – which includes Beijing, Tianjin and three northern provinces – one of the three economic engines of China.

But this area already has a dense and mature gas pipeline network with various sources. Power of Siberia 2, which will potentially increase the area’s supply by 50 per cent, can expect to face fierce competition from the fast-growing capacity of the Tianjin-Tangshan coastal LNG imports, offshore gas from the Bohai Sea, and domestic gas from Shaanxi, even the gas imports from the other two Russian pipelines. This oversaturation represents a clear and unnecessary capital expenditure.

In addition, around half of the gas consumption in the north of China is for household use, especially winter heating, meaning the area’s gas demand will see significant seasonal fluctuations. If the gas from Power of Siberia 2 has to travel further south to find consumers when demand is low, its costs will rise, rendering the project even less economically viable.

As China forges ahead with its energy transition, the country aims to reach peak carbon emissions by 2030, the year the Power of Siberia 2 pipeline is projected to begin operations. Under the cap, China will need to cut an equivalent amount of emissions expected from the 50 billion cubic metres of gas brought annually by Power of Siberia 2.

At the same time, China’s unprecedented pace of renewable energy installation continues to drive down the costs of wind and solar power, dramatically increasing their share in power capacity and generation.

Due in part to this breakneck buildout, the power sector’s carbon emissions may peak five years earlier than the targeted 2030. Increasing gas supplies as a bridge away from China’s coal-dependent economy increasingly makes less sense for its energy transition.

On the political front, Russia has long been alarmed by China’s influence on its Far East. Even now, as Putin significantly strengthens ties with China to offset how Russia’s war with Ukraine has withered partnerships – and energy markets – elsewhere, China’s rising power and global influence is a concern. Russia refused to let China invest in the second pipeline on Russia’s side. It is likely to insist on the same “you pay, I deliver” mode for Power of Siberia 2.

Russia may also be wary of China’s efforts to placate European nations as China seeks a closer relationship with the European Union at a time when Beijing and Washington are increasingly at odds. As Power of Siberia 2 is designed specifically for the Chinese market, Russia could tip the balance of power.

The war in Ukraine and resulting economic sanctions continue to play a role in Russia’s push for Power of Siberia 2 in China. But the war won’t last forever, and Russia is unlikely to maintain the fire sale for long.

Unlike the more liquid LNG markets, gas pipelines present a long-term sunk cost that is more difficult to shift. If China puts too much weight on this “single source buyer” project, it faces economic and political risks that threaten to upend its energy security agenda and derail its energy transition.

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The buildout of oil pipelines continues at a global scale, according to the May 2024 Global Oil Infrastructure Tracker (GOIT) data release from Global Energy Monitor. In total, the world is constructing nearly 11,000 kilometers (km) of crude oil transmission pipelines — about the length of the Earth’s diameter — with an additional 22,700 km proposed. Compared to the same time last year, this represents an 8% increase in total km in development.

The infrastructure currently under construction is estimated to cost US$25.5 billion in capital expenditure, and the additional proposed km would add US$106.2 billion more. The lion’s share of costs will fall on Africa and Asia, who lead the buildout.

Some regions are building pipelines with the goal of becoming exporters, like coastal sub-Saharan Africa countries. Elsewhere, major importers like India and China are adding pipelines to existing networks to serve refineries and petrochemical complexes. But some of the more consequential buildouts are happening in traditional oil production regions like the Persian Gulf in Western Asia, and the U.S. and Canada in North America, who are expanding to maintain their foothold as global oil exporters. Many of these pipeline buildouts are led by state-owned companies, though others like France’s TotalEnergies and the U.S.’s ConocoPhillips are in the mix.

The fervor for oil exports is exemplified by developments in North America, in particular along the U.S. Gulf Coast. While the U.S. isn’t leading the global buildout by km or costs, these shorelines are already a major global export hub, with terminals and refineries processing crude oil and other liquids from the Permian basin and the Cushing, Oklahoma storage hub to send them abroad.

Last year, the U.S. hit record oil production and export numbers, and this year, the trend is expected to continue, with recent forecasts of even higher production. But the Permian’s takeaway capacity — the volume of oil and gas it can export now with existing pipeline infrastructure — is near its limit and may be maxed out by the end of 2024. Thus, each new pipeline and expansion project adds only marginal takeaway capacity that producers bank on. Currently, seven major projects are in development to reduce that constraint, four of which connect directly to proposed oil export terminals.

There are four crude oil export terminals currently in development off the Texas and Louisiana coasts, each of which would be able to dock giant crude carriers and export up to two billion barrels of oil per day. The most imminent is Sea Port Oil Terminal (SPOT), which in April 2024 was issued a deepwater port license by the U.S. Maritime Administration (MARAD).

In the U.S., the development of pipelines and export terminals will continue to move in tandem. Additional export capacity will spur further oil production, and the oil production will be accompanied by increased gas production, as the majority of gas produced in the Permian is associated gas (meaning it is found with petroleum deposits and comes out of the ground alongside oil). The recent pause on liquefied natural gas (LNG) export approvals by the Biden administration has been a temporary obstacle in the global LNG export race. But because much of Permian gas is associated, approving and building oil export terminals could erode any case for further pausing or rejecting LNG export capacity. The oil and gas have to go somewhere.

At a time when scientists agree any additional fossil fuel extraction will cause unsafe levels of climate warming — and in a geopolitical context where additional fossil fuel exports out of the U.S. decrease energy security everywhere by increasing energy price volatility at home and abroad — expansions like this are climate-damaging bets on an uncertain future.

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• The Biden Administration’s January 2024 decision to pause approvals of non-Free Trade Agreement (non-FTA) export authorizations for liquefied natural gas (LNG) export proposals impacts 88.9 million tonnes per annum (mtpa) of proposed capacity, according to analyses from Global Energy Monitor (GEM) and Sierra Club.
• These projects represent one-quarter of all export capacity in development in the United States and one-tenth of all such capacity globally.
• The pause has a minimal impact on near-term U.S. LNG exports and would not compromise energy security in Europe, which is already receiving sufficient LNG from the U.S..
• Only 14% of potential capacity additions over the next three years are affected by the pause. Meanwhile, U.S. LNG export capacity is poised to increase by more than half over the same time period, and Europe’s gas demand is forecast to decline.

In January 2024, the Biden Administration announced a pause on the Department of Energy (DOE) authorizing proposed LNG terminals to export gas to non-FTA countries, during which it will reassess whether such projects are in the public interest, the key criterion for authorization. The impacts of the pause on U.S. and global LNG development, including its effects on Europe, have at times been misunderstood or misrepresented, for instance, with the American Petroleum Institute calling the pause a “win for Russia” and “broken promise to U.S. allies.”

This briefing is intended to help contextualize the impacts of the pause on U.S. projects, which could curb an already overblown U.S. LNG buildout without compromising Europe’s energy security — crucially, if the pause holds or leads to new guidance discouraging future DOE authorization of these projects. GEM’s analyses draw on global LNG terminal data from the Global Gas Infrastructure Tracker and Sierra Club’s assessment of which projects may be impacted by the pause given permitting data in its US LNG Export Tracker.

The pause could curb the overbuild of U.S. LNG export projects

The U.S. was the world’s largest exporter of LNG in 2023, and with 336.9 mtpa of new LNG capacity in development — projects proposed or under construction — its pipeline of projects dwarfs that of every other gas exporting country. As GEM has previously written, the U.S. LNG buildout is not in the public interest — LNG exports raise domestic gas prices, lock in fossil fuel emissions abroad, and threaten Gulf Coast communities already burdened by oil and gas pollution.

Sierra Club’s tracking of project permits finds that twelve U.S. LNG projects in development are subject to the Biden Administration’s pause on LNG export authorizations to non-FTA countries (see Table 1). Because the list of FTA countries excludes much of the global LNG market, including virtually all of Europe and Asia, most export projects cannot be commercially viable without this authorization, and the pause effectively freezes these pending applications.

In total, paused projects amount to 88.9 mtpa of proposed export capacity, or one-quarter of all LNG export capacity in development in the United States and one-tenth of all such capacity globally. Two projects in Mexico are affected by the pause as well, Saguaro Energía LNG Terminal and New Fortress Altamira FLNG Terminal, which have 6.13 mtpa and 3.07 mtpa export capacity pending DOE approval, respectively.

A halt to these projects, if sustained, could have a significant impact on curbing global greenhouse gas emissions. The potential annual emissions associated with these projects could be as high as 381 megatonnes CO₂ equivalent, on par with that of almost 100 coal plants. Stopping the development of these projects would be in line with the International Energy Agency’s net zero pathway, under which global LNG exports should peak by the middle of the decade.

The pause does not harm Europe’s energy security

The LNG pause would have a minimal impact on U.S. LNG exports in the near-term, despite oil and gas industry claims that it would compromise Europe’s energy security. According to GEM and Sierra Club data, just 14% of potential capacity additions within the next three years (2024 to 2026), totaling 17.2 mtpa, are impacted by the pause. The U.S. is already surpassing its LNG commitments to Europe, and U.S. export capacity is poised to increase more than 50% over the next three years from projects unaffected by the pause that are in construction or have reached final investment decisions (FIDs).

Europe, meanwhile, has emerged from its gas crisis and is expected to need less U.S. LNG in the coming years. The Institute for Energy Economics and Financial Analysis (IEEFA) forecasts that EU gas demand could fall 16% by 2030 and that “the continent’s LNG demand [will] peak in 2025 — far earlier than U.S. export projects affected by the pause would enter the market.” Declining gas demand is driven by Europe’s accelerating energy transition, including improved energy efficiency, demand management, and increased deployment of renewables. And given LNG’s vulnerability to price volatility and supply disruptions, these trends—not increased U.S. gas exports—will ultimately enhance Europe’s energy security.

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Key points

• 74 new oil and gas projects could emit 2.4 million tonnes of methane annually before 2030.
• Half of those emissions come from just twelve oil and gas fields under development, and roughly a third come from four fields in Saudi Arabia and two fields in Guyana. 
• Potential methane emissions from select fields in development were larger than previous company-wide figures reported to an industry watchdog

The world’s oil and gas producers have proposed extraction projects scheduled to go into operation and reach peak production by 2030 that have the potential to emit nearly as much methane as the entire fossil fuel production sector in Europe, according to new data and analysis from Global Energy Monitor (GEM). 

A first-of-its-kind assessment of data in the Global Methane Emitters Tracker shows that 74 new oil and gas projects have the potential to emit 2.4 million metric tonnes of methane annually at a time when deep cuts are necessary to mitigate climate change.

One hundred and fifty-seven countries and the EU committed to slash global methane emissions 30% before the end of the decade by signing up to the Global Methane Pledge. The International Energy Agency has also called on the fossil fuel industry to cut methane emissions 75% by 2030, in order to be on pace for net zero emissions in 2050, which aligns with the goals of the Paris Agreement.

But the oil and gas extraction projects analyzed would amount to 3% of 2023 methane emissions from oil and gas production, if they operate using current practices. Under that scenario, countries and operators would need to make steeper cuts in emissions elsewhere to stay on track with the Global Methane Pledge and climate targets.

At the same time, methane emissions continue to be significantly underreported. The majority of the top 20 operators pursuing new projects did not provide data to the latest publicly available disclosure report by the International Methane Observatory’s Oil and Gas Methane Partnership (OMGP 2.0). 

For some companies, GEM’s analysis finds that potential methane emissions from select fields in development were larger than 2022 company-wide figures reported to OGMP 2.0.

Methane management requires accurate measurement, and major discrepancies between the data reported by oil and gas companies and bodies set up to provide oversight are hindering these efforts.

Sarah Lerman-Sinkoff, Project Manager for the Global Methane Emitters Tracker

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Data in the Global Oil and Gas Extraction Tracker show at least 20 fields were approved in 2023, sanctioning the extraction of eight billion barrels of oil equivalent (boe). By the end of the decade, companies are aiming to sanction nearly four times that amount — 31.2 billion boe across 64 additional fields. In addition, 19 new fields containing roughly 7.7 boe were discovered in 2023.

The report finds that, since the International Energy Agency issued a warning in 2021 that no new oil and gas fields were needed to stay within a 1.5°C scenario, oil and gas producers sanctioned a total of at least 16 billion boe across 45 projects and discovered at least 20.3 billion boe across 50 projects. 

Despite this contradiction, the oil and gas industry remains steadfast in its plans to continue developing new fields, as the majority of the top producing countries anticipate increasing their production through the end of the decade. 

South America and Africa are global hotspots for new oil and gas projects, while four countries that previously had little to no production — Cyprus, Guyana, Namibia, and Zimbabwe — account for over a third of the volumes producers are hoping to exploit.

Oil and gas producers have given all kinds of reasons for continuing to discover and develop new fields, but none of these hold water. The science is clear: No new oil and gas fields, or the planet gets pushed past what it can handle.

Scott Zimmerman, Project Manager for the Global Oil & Gas Extraction Tracker

4 April 2024: This report has been amended to clarify its definition of project approvals.

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• Europe is developing new liquefied natural gas (LNG) terminals and gas pipelines as if the region were still in crisis, even though it is in a far more secure position than it was two years ago, following Russia’s full-scale invasion of Ukraine. 

• LNG import terminals and pipeline infrastructure in development — projects that have been announced or are in construction — would boost Europe’s total gas import capacity by 55%, at a cost of €84.1 billion, and widen existing overcapacity.

• Germany, Italy, and Greece — which are developing the most gas infrastructure in Europe — are together responsible for half of these costs.

• Projects that are already under construction could, if used at full capacity, result in additional annual greenhouse gas emissions equivalent to that of 50 coal plants. Including proposed projects, this figure grows six-fold.

Europe continues to pursue a costly and emissions-intensive buildout of gas import infrastructure capacity as if the region were on crisis footing, finds a new report from Global Energy Monitor (GEM).

According to data in the Europe Gas Tracker, European countries are developing 248.7 billion cubic meters per year (bcm/y) in new LNG import capacity and 16,491 kilometers (km) in new gas transmission pipelines, which includes cross-border pipelines capable of importing a further 46 bcm/y of gas into Europe. 

In the last year, the slate of new projects in development has grown by 9% for LNG import capacity and 18% for gas pipelines length.

GEM estimates that the total capital expenditure in new European gas infrastructure could be €44.4 billion for LNG terminals and €39.7 billion for gas pipelines, for a total of €84.1 billion. Of this amount, projects already in construction total €10 billion. 

Germany, Italy, and Greece, which are developing the most gas infrastructure in Europe, are together responsible for half of these plans (€45.3 billion).

The planned gas buildout is at odds with the European Union’s (EU) emissions goals. The EU’s Fit for 55 plan aims to reduce emissions by 55% by 2030, and in February, the European Commission called for an additional goal of reducing emissions by 90% by 2040. 

GEM estimates that the LNG terminals and gas pipelines already in construction in Europe, if fully used, could result in an additional 195 megatonnes CO₂ equivalent (CO₂e), on par with the annual emissions of 50 coal plants. Including proposed projects, the additional annual emissions could grow six-fold to 1.1 gigatonnes CO₂e, equivalent to that of nearly 300 coal plants, or a quarter of Europe’s emissions in 2020. 

Although Europe’s LNG plans have advanced quickly, several high-profile project setbacks in 2023 could indicate waning enthusiasm for LNG. Import projects in Ireland, Latvia, and Poland totaling 16.8 bcm/y faced environmental objections or lost support from their backers, casting doubt on their futures. In total, 17.6 bcm/y of LNG import capacity in development are shelved and at least 60.6 bcm/y are delayed.

Europe is in a far different, and more secure, position today than at the start of its gas crisis. It is on track to eliminate Russian gas imports, overall gas demand is on the decline, and generation from renewables has reached new heights. Doubling down on new gas projects now would be completely out of step with Europe’s energy transition.

Robert Rozansky, Project Manager for the Europe Gas Tracker

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Data in the Global Oil and Gas Plant Tracker show that, to achieve the scenario outlined by the International Energy Agency (IEA) in its October 2023 Net Zero Emissions (NZE) roadmap to phase out unabated gas power by 2050, an average of 64 gigawatts (GW) of oil- and gas-fired capacity should come offline each year until 2035, which is five times the capacity retired annually since 2020. 

Fifty-two GW has been retired since 2020, or an average approximately 13 GW each year. Quickening the pace of retirements is even more urgent given that just 80 GW of oil and gas capacity already has an announced retirement of 2035 or earlier. 

Oil and gas plants would have to be retired at an even faster rate to keep in line with climate targets if any of the projects currently in development globally — 260 GW of announced capacity and 265 GW in pre-construction stages — become operational.

The IEA NZE roadmap states that unabated oil- and gas-fired capacity must decrease by one-third by 2035 and by nearly half by 2040. Unabated oil and gas should fall below five percent of total power generation by 2040 and should effectively be phased out by 2050.

GEM data predict that if all oil and gas plants in development are built, global overcapacity will run to 435 GW in 2030, 650 GW in 2035, and 697 GW in 2040.

This means that any new gas plants built in the future risk becoming stranded assets and either being decommissioned before the end of their economic life, having to include carbon capture and storage, or experiencing significant underutilization.  

Yet countries continue to build new fossil fuel power plants, representing a critical threat to aims of the Paris Agreement to limit temperature increases to 1.5°C. Two hundred and nine GW of oil- and gas-fired power plants is currently under construction, more than a quarter of the 734 GW of capacity in development. 
By comparison, 578 GW of coal-fired power capacity is currently in development globally. Yet unlike coal, where development is concentrated in a few countries, the gas expansion is global, covering almost every country in the world.

Amid record-breaking renewable energy power generation and capacity additions in 2023 and the IEA projecting that global fossil demand will peak by 2030, a fundamental shift away from these risky fossil power investments is imperative. 

One place to start is with the aging global oil and gas power fleet. In particular, gas-powered steam turbines are the oldest in service, with a global average capacity weighted age of 37 years, representing an untapped potential to retire these inefficient older units.

*See more information about the methodology for these calculations. 

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• Liquified natural gas (LNG) projects in development — those proposed or under construction — total 917 million tons per annum (mtpa) of new export capacity and 705 mtpa of new import capacity, representing an 18% and 4% year-on-year increase, respectively, at an estimated US$1 trillion in investment.
• Of this total, construction continues on 193 mtpa in export capacity and 203 mtpa in import capacity, which when brought online will boost global capacity 41% and 19%, respectively.
• Half of all export projects are under construction in the United States and Qatar.

Global LNG project developments spurred on by Russia’s invasion of Ukraine materialized this year, as the U.S. and Qatar solidified their positions as top developers of export capacity, whilst Asian and European countries scrambled for new import capacity, according to a report from Global Energy Monitor.

According to data in the Global Gas Infrastructure Tracker, the leading countries developing new export terminals are the U.S. (336.9 mtpa), Russia (164.1 mtpa), Canada (75.8 mtpa), Mexico (69.3 mtpa), and Qatar (49 mtpa).

While relatively little new LNG export capacity has come online in recent years, a wave of new projects — half of which are under construction in the United States and Qatar, totalling 74 mtpa and 33 mpta, respectively — could saturate the global LNG market, increasing competition among exporters and rendering some projects unprofitable. The ensuing supply glut could leave governments and investors with costly stranded assets.

New import capacity is dominated by Asia (454 mtpa) and Europe (183 mtpa), with China (267.9 mtpa), India (75.2 mtpa), and Germany (65.4 mtpa) having the most capacity in development.

However, LNG demand in Europe could prove short-lived as the continent pursues its decarbonization agenda, and the price sensitivity of many Asian importers has called into question LNG demand growth forecasts.

Building new LNG projects when fossil demand is expected to peak this decade is a risky proposition for investors and governments alike. If even a fraction of these projects go ahead it would threaten to further delay the energy transition during a critical period.

Robert Rozansky, Global LNG Analyst at Global Energy Monitor

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• Approximately 69,700 kilometers (km) of gas transmission pipelines are under construction globally, an 18% increase over the previous year, at a cost of US$193.9 billion
• Asia leads the world in pipeline construction, accounting for 82% at an estimated cost of US$117.2 billion, with China and India responsible for 65% of global construction
• Globally 228,700 km of gas transmission pipelines are in development — counting projects that are in construction or have been proposed — at a total price tag of US$723 billion

The length of gas transmission pipelines currently under construction is enough to circle the Earth one-and-a-half times, representing an 18% increase over last year, finds new research from Global Energy Monitor.

Data in the Global Gas Infrastructure Tracker show that approximately 69,700 km of gas transmission pipelines are under construction globally, at a cost of US$193.9 billion. When counting the number of projects that have been announced, a total of 228,700 km of gas transmission pipelines are in development worldwide, at a total price tag of US$723 billion. 

Much of the buildout is in Asia, with 14 of the 15 longest pipeline projects under construction located there. Outside of the region, the U.S. is another top builder of gas pipelines, aiming to bolster export capacity out of the Permian Basin and Haynesville Shale in order to capitalize on present and future European and Asian import markets. Australia, another major gas exporter, is taking a similar approach.

South America is also poised for significant gas infrastructure growth in the coming years after inaugurating a pipeline carrying gas from the Vaca Muerta formation, the second-largest shale gas reserve in the world, in July 2023.

Asia is gambling on more fossil fuels and encouraging other major economies to do the same. Across the region the price of renewables has come down, gas emissions are considered to be worse than coal when transport is factored in, and peak gas demand has been predicted by the end of this decade. This gas infrastructure is risky and thoughtless.

Baird Langenbrunner, Project Manager for the Global Gas Infrastructure Tracker at Global Energy Monitor

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• Global oil- and gas-fired power plants in development — projects that have been announced or are in the pre-construction and construction phases — increased 13% last year to 783 gigawatts (GW)
• Nearly two-thirds of this capacity and cost is in Asia, where 514 GW at an estimated US$385 billion are in development, mainly in China and Southeast Asia
• If built, the existing global oil and gas fleet would grow by a third at an estimated cost of US$611 billion in capital expenditure

Driven by China and countries in Southeast Asia, global oil- and gas-fired capacity in development increased 13% last year, even as the region experienced volatile price swings and hosted some of the lowest costs for green electricity, finds a new report from Global Energy Monitor.

The Global Oil and Gas Plant Tracker catalogs nearly 12,000 units of every known oil- and gas-fired power plant in the world and shows that five countries — China, Brazil, Vietnam, Bangladesh, and the United States — make up almost half of all capacity in development.

Asia has nearly two-thirds of the world’s oil and gas plant capacity in development, with China hosting a fifth of the world’s in development capacity, more than the next three leading  countries — Brazil, Vietnam, and Bangladesh – combined.

Construction began on 207 gigawatts of new oil- and gas-fired power plants, a 23% increase over the previous year. Almost three-quarters of this capacity is in Asia, mainly concentrated in China.

While high LNG prices have pushed some countries in Asia, including Bangladesh and Pakistan, away from procuring LNG cargoes, analysts have also shown that the costs of electricity from solar and wind is on average below the cost of gas-fired power, and well below such cost in China.

Gas continues to grow even with its reputation unraveling as a cheaper, cleaner and reliable transition fuel. Price volatility has led many countries to turn their backs on gas plans. The severity of gas’ impact on the climate is better understood everyday because it leaks the potent greenhouse gas methane. And extreme weather events are causing fossil fuel power plants to fail. Still, the transition away from oil and gas is not happening anywhere near fast enough.

Jenny Martos, Project Manager for the Global Oil & Gas Plant Tracker at Global Energy Monitor

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The report includes data from the Global Oil and Gas Extraction Tracker detailing at least 19 new fields with estimated reserves of over 540 billion cubic meters of gas – more than the proven reserves in all of the European Union – that reached or are expected to reach final investment decisions between 2022 and 2025. Over 75% of these in-development fields are located in Malaysia and Vietnam.

The International Energy Agency has said that, “Beyond projects already committed as of 2021, there are no new oil and gas fields approved for development in [its 1.5° Celsius] pathway.” 

The IEA already expects oil and gas production in Southeast Asia to be about 145 bcm per year higher by the middle of the century than what would be expected in its ‘Sustainable Development’ Scenario. 

With the development of these new fields, the region would only widen the gap between its current trajectory and a development pathway compatible with keeping temperature increases below 1.5° Celsius.

Energy demand is increasing across Southeast Asia as economies grow, but ramping up gas production is not a long-term solution. Meeting demand via cost-effective, renewable sources insulates the region from volatile gas prices and is a greener path forward.

Scott Zimmerman, Project Manager for the Global Oil and Gas Extraction Tracker

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Over 60% of global gas-fired capacity in development is based in Asia. More than half of this capacity is concentrated in East Asia and Southeast Asia. With an estimated cost of nearly US$338 billion in capital expenditure, these units would emit over 750 million tonnes of CO2 annually if they become operational. Yet Russia’s invasion of Ukraine has led to price spikes in the cost of liquified natural gas (LNG), which seems to have slowed the growth of gas infrastructure. Approximately 81GW of previously planned capacity in Asia was cancelled in 2022 and 2023. There is still time to halt or limit the gas expansion in Asia, since  approximately 70% of the gas-fired capacity in development is still in the announcement and pre-construction stages and can be stopped in the pipeline. 

Countries in East and Southeast Asia are on the verge of an explosive growth in the development of gas-fired power plants, as countries aim to meet growing energy demand while turning away from coal power in search of lower emissions alternatives. With the Asian gas market predominantly reliant on LNG as opposed to piped gas, the 440 gigawatts (GW) of in-development gas-fired capacity in the region would mean a doubling of current LNG imports. This volume is equal to more than 6,500 additional cargoes from a standard 170,000 cubic meter carrier vessel, enough to meet projected demand of roughly 484 million tonnes per annum (mtpa). By comparison, the total volume of LNG imports to Asia in 2022 was only 263.76 million tonnes.

Yet some countries have recently turned away from gas, largely due to the price volatility of imported LNG and competition from cheaper renewable energy. The political instability and price volatility associated with LNG markets is expected to continue, making it an insecure resource for countries to rely on as they expand their energy systems. Before major investments are made, Asian countries still have time to prevent a potentially devastating gas expansion and lock-in. 

Proposed growth: significant and consequential

Over 60% of the gas-fired capacity in development globally i.e. projects in the announced, pre-construction, and construction phases is based in Asia. More than half of this capacity is concentrated in East Asia and Southeast Asia (Table 1, Figure 1). 

In East Asia, China leads with an in-development capacity of 117 GW. Of this capacity, 32% is already in the construction phase. China is followed by Taiwan, which has 25 GW in development. Overall, East Asia represents24% of the global in-development capacity and 39% of in-development capacity in Asia. 

In Southeast Asia, Vietnam leads with 44GW of gas power capacity in the pipeline. However, almost all of this capacity is in the proposal and pre-construction stages. The Philippines, with around 15 GW in development, shows a similar picture, as over 80% of its gas power projects are in the proposal and preconstruction stages. Overall, Southeast Asia represents 14% of global in-development capacity and 23% of in-development capacity in Asia. 

The proposed gas expansion will be detrimental to climate goals, as any new fossil-based projects are “incompatible” with a target to limit planetary warming to 1.5° Celsius. If operational, these units would emit over 750 million tonnes of CO2 annually, a near doubling of the current annual CO2 emissions of the existing operational fleet of gas power plants in Asia, which is roughly 1,300 million tonnes. 

Asia is already witnessing the catastrophic impacts of climate change in the form of floods, severe heat waves, and other extreme weather events. According to a World Meteorological Organization (WMO) report, Asia experienced over 100 natural hazards in 2021, 80 percent of which were flood and storm events. These caused around 4,000 deaths, directly affected nearly 50 million people and resulted in economic damages totalling US$35.6 billion. 

Relying predominantly on imported LNG fuel is also an energy security risk for the region, as it exposes countries to global economic and political instabilities. Bangladesh and Pakistan struggled to afford LNG due to high prices, with Bangladesh purchasing LNG at a cost up to ten times higher than in mid-2020 and implementing rolling blackouts, which could continue until 2026. 

At the same time, domestically-produced, renewable power can alleviate these issues and set Asian nations on a path of energy independence. Renewable energy technologies like onshore wind and solar projects present a wiser investment choice, as they now cost on average 40% less than new coal or gas plants. 

Recent project cancellations and re-considerations

Russia’s invasion of Ukraine led to LNG price spikes, which seem to have slowed the growth of gas infrastructure. Approximately 81 GW of previously planned capacity in Asia was cancelled in 2022 and 2023, representing 73% of global capacity cancellations in the last year. 

Gas price increases and surging competition from renewables have also weakened the prospects for gas demand in the region. A predominantly mild winter and suppressed gas demand have led to a slight decrease in global gas prices. Still, prices remain two to three times higher than the average price  prior to COVID-19, and prices are expected to stay elevated for the next few years because of tight LNG supplies that won’t see a considerable increase until the mid-2020s. 

Consequently, some Asian nations have started seeing gas, especially LNG, as an expensive and unreliable fuel source. Last year, the International Energy Agency (IEA) slashed in half its 2022 forecast for emerging Asian gas demand growth from 2021-2025. 

Pakistan has announced plans to phase out imported LNG as a power generation source in the long run. Instead, the country aims to increase its domestic power capacity, including solar and wind. Thailand has also decided to accelerate its shift to renewable energy to reduce its dependence on foreign fuel, planning to more than double its renewable capacity by 2030. 

In the Philippines, its first LNG terminal was commissioned this year. However, competition from renewables might result in the underutilization of this costly infrastructure, and the long-term economic sustainability of LNG-fueled power is already being questioned, as two power supply agreements are being renegotiated due to high costs. The revised power supply agreements will likely pass the high fuel costs on to consumers, who are already paying some of the highest tariffs in Asia. 

These decisions might portent a window of opportunity for clean power technologies to increase their share in the energy mix. Recently, the Asian Development Bank and the Global Energy Alliance for People and Planet launched a new capital fund to expedite the green energy transition in South and Southeast Asia. Such initiatives could further support the transitions to renewables and away from fossil fuels in Asia. 

A window of opportunity to stop further gas lock-in

The silver lining to these project cancellations is a clearer path to achieving the 1.5C target. Yet obstacles persist: for instance, Japan continues to push its “Green Transformation” policy, which promotes and finances LNG; ammonia co-firing; fossil hydrogen; and carbon capture, utilization, and storage across Asia, all of which are known attempts to prolong the use of fossil fuel technologies rather than relying on clean energy resources. Policies like this often portray LNG as a cleaner alternative to coal even though the methane emissions released during the production of gas make LNG equally harmful for the climate. 

There is still time to slow or stop the gas expansion in Asia. Currently, roughly 70% of the gas-fired capacity in development in Asia is still in the announcement and pre-construction stages (Table 1) and can be stopped in the pipeline before any further investments are made. As Fatih Birol, Director of the IEA recently wrote, “the push by some companies and governments to build new large-scale fossil fuel projects is not only a bet against the world reaching its climate goals — it is also a risky proposition for investors who want reasonable returns on their capital.”

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