• Aging infrastructure, unrealized plans, and high costs continue to limit nuclear’s role in swift decarbonization, while solar and wind power are expanding rapidly and outpacing nuclear in new capacity and generation.
• Nearly 40% of all nuclear power ever proposed has been cancelled: 566 gigawatts (GW) of nuclear capacity has been cancelled worldwide, more than what is currently operational (401 GW) or retired (116 GW) combined.
• Europe’s nuclear sector has lost 122 GW of planned capacity to cancellations, more than the operating nuclear fleet of any single country worldwide. An additional 68 GW has been retired, and 90% of the remaining reactors are more than 35 years old. In contrast, European wind and utility-scale solar capacity under construction or in pre-construction outweighs nuclear by a factor of more than 13 to 1.
• Australia’s moratorium on nuclear, lengthy projected development timelines, high costs, lack of expertise, and strong public and policy preference for renewables mean nuclear is unlikely to play a significant role in filling the gap left by the country’s planned coal phaseout by 2038.

Limiting warming to 1.5°C is the internationally recognized target of the Paris Agreement, as reaffirmed at recent UN climate summits. However, scientific assessments indicate that this threshold is likely to be surpassed within the next three years, underscoring the urgent need for rapid decarbonization. In this context, the approaching target breach is driving a broad shift away from fossil fuels, and nuclear energy has been reassessed as a potential low-carbon power option. Nuclear power, although not classified as renewable, has seen increased policy support and investment in recent years. COP28 and COP29 formally recognized its potential role, and 31 countries pledged to triple global nuclear capacity by 2050.

The comprehensive, citation-based data in GEM’s Global Nuclear Power Tracker (GNPT) monitors not only operational nuclear plants but also uniquely maps the full development pipeline, including cancelled projects. Often overlooked in other datasets, nuclear project cancellations account for 38% of all capacity ever proposed — about 566 GW, equivalent to nearly 120% of India’s entire power generation capacity from all sources. This briefing focuses on Europe, where nuclear infrastructure is extensive but aging, and Australia, where nuclear power has been discussed, but not yet deployed. In both jurisdictions, the GNPT indicates that new nuclear deployment is not a viable approach to meet climate targets.

Europe: wind and solar plans outpacing nuclear fourteen to one

Nuclear energy’s role in European decarbonization is limited by aging infrastructure, extended construction timelines, escalating costs, and strong competition from renewables. Of all nuclear capacity ever planned for Europe, two-fifths of it has either been cancelled (25%) or retired (15%), while only 2% is currently under construction. European cancellations alone total 112 GW of capacity, exceeding the operating nuclear capacity of any single country worldwide. GNPT data reveal that nuclear projects consistently face high risks of delay, cost overruns, and abandonment. For example, unit 3 of Finland’s Olkiluoto project required 17 years to complete, while unit 4 was cancelled in 2015. Most projects now under development are not expected to begin operation until the next decade, negating their potential contribution to the 1.5°C climate target. In contrast, solar and wind power have already demonstrated rapid scalable deployment and measurable emissions reductions, offering near-term climate benefits.

Figure 1

GEM’s GNPT shows that as of September 2025, Europe operates 157 gigawatts (GW) of nuclear capacity, over 90% of which comes from reactors more than 35 years old. Retirements are steadily reducing total operating capacity. In France, the continent’s largest nuclear operator, generation has declined due to maintenance challenges and unplanned outages, including a record heatwave in July 2025 that disrupted reactor cooling. Compared to 2005, French nuclear output was 16% lower in 2024, even after the addition of its first new unit in nearly two decades. EU-wide, nuclear’s share of electricity generation fell from 25% in 2005 to under 20% in 2024. Of the 9.3 GW of new European nuclear capacity under construction, GEM data show that most is intended to replace retiring units rather than expand total capacity.

Recent European reactor projects such as Finland’s Olkiluoto 3, France’s Flamanville 3, and the UK’s Hinkley Point C have experienced delays exceeding ten years and steep cost overruns. All employ the European Pressurized Reactor (EPR) design, whose first-of-a-kind complexity and lack of standardized construction methods have led to inefficient implementation. Efforts to develop SMRs are underway in multiple European countries including the UK and France, but no commercial SMRs are yet in operation and first deployments are unlikely before the early 2030s due to regulatory, cost, and public acceptance barriers.

In contrast, renewable deployment continues at scale. GEM’s Global Integrated Power Tracker indicates that over 600 GW of wind and utility-scale solar capacity is in pre-construction or construction across Europe, which together is over fourteen times that of nuclear. Even when accounting for the higher capacity factors of nuclear generation, planned wind and solar additions are expected to provide a substantially greater contribution to decarbonization. Much of this renewable capacity is expected to be operational well before new nuclear projects, due to renewable project lead times typically ranging from one to four years, compared to a decade or more for nuclear. Within the EU specifically, in mid-2025, total solar generation (22.1%) has already surpassed nuclear (21.8%) for the first time. Battery storage, driven by declining costs, is on track to expand from 22 GWh in 2024 to about 120 GWh by 2029, supporting deeper renewables integration. At the same time, pumped-storage hydropower remains a cornerstone of large-scale energy storage capacity.

Figure 2

Australia’s coal phaseout by 2038 makes nuclear timeline infeasible

Australia is another major economy where nuclear power is unlikely to contribute to emissions reduction goals in the next one to two decades despite recent calls by some political stakeholders to revisit nuclear plans. The country’s longstanding moratorium on nuclear energy, reflected in GEM’s GNPT as a total absence of operational or prospective facilities, underscores nuclear’s limited potential as a near-term decarbonization option, especially when contrasted with the country’s robust expansion of wind and solar capacity.

Australia plans to retire its entire coal-fired power fleet — which currently supplies around half of the country’s electricity — by 2038. This transition will necessitate the deployment of fast, reliable, and cost-effective replacement energy sources within the next thirteen years. GEM data show that new nuclear reactors have historically averaged just under eight years from the start of construction to completion since the mid-1960s, excluding pre-construction periods and cancelled projects. The Commonwealth Scientific and Industrial Research Organisation (CSIRO) estimates that construction timelines for nuclear plants in Australia are likely to be at least five years longer than the global average, resulting in an expected construction period of approximately thirteen years from groundbreaking to commissioning.

Figure 3

To achieve operational status by 2038, new nuclear projects would therefore need to begin construction before the end of this year. When factoring in the extensive pre-construction phases, which often span multiple years, the feasibility of introducing new nuclear capacity in Australia within the required timeframe to replace retiring coal-fired power plants becomes extremely unlikely.

Nuclear also remains one of the highest-cost forms of electricity generation per megawatt-hour, with delays and cancellations often transferring financial risk to taxpayers. Compounding these problems are Australia’s lack of a nuclear-trained workforce and absence of regulatory frameworks for safe and timely project delivery. Public sentiment and policy further challenge nuclear’s prospects. Most Australians supportmaintaining the current moratorium, as reaffirmed in recent parliamentary inquiries, and national energy policy prioritizes wind, solar, and storage. In the last ten years, Australia has added over 21 GW of new wind and utility-scale solar capacity, and the government target of 43% emissions reduction by 2030 is widely considered achievable through sustained deployment of wind, solar, and storage, which remain less expensive and faster to scale than nuclear.

Conclusion

The high costs and long timelines of new nuclear power plants severely limit any impact on near-term decarbonization goals. Wind and solar are achieving rapid scale and greater cost-effectiveness, making them central to immediate emissions reductions required for the 1.5°C pathway. SMRs remain commercially unproven, and current risks and deployment rates for nuclear overall are insufficient for 2030 climate targets. Robust decarbonization and successful action toward reaching emissions reductions will require technology-neutral, system-level planning, including a realistic evaluation of nuclear’s proposed role.

About the Global Nuclear Power Tracker

The Global Nuclear Power Tracker (GNPT) is a worldwide dataset of nuclear power facilities. The GNPT catalogs every nuclear power plant unit of any capacity and of any status, including operating, announced, pre-construction, under construction, shelved, cancelled, mothballed, or retired.

Media Contact

Joe Bernardi

Project Manager, Global Nuclear Power Tracker

joe.bernardi@globalenergymonitor.org

The post Nuclear outpaced fourteen to one by wind and solar in Europe appeared first on Global Energy Monitor.

Today, the  Centre for Research on Energy and Clean Air and Global Energy Monitor have published their H1 2025 coal power review that reveals a boom in commissioned coal projects, while new and revived proposals are the highest in a decade, both upward trends after some signs of cooling in 2024.

In H1 2025,  21 gigawatts (GW) of coal power were commissioned, the highest amount in the first half of the year since 2016, with projections for the full year exceeding 80 GW. This increase in commissions follows on the tail of the 2022-2023 coal power permitting surge that saw two new coal projects permitted per week, on average, totalling more than 100 GW of coal power approved per year. This trend will likely continue into 2026 and 2027, unless policy action is taken.

Although only 25 GW were permitted in H1 2025, new and revived projects came to 75 GW in H1 2025, the highest in a decade, and construction starts and restarts reached 46 GW, equivalent to the entire coal power capacity of South Korea. 

This rush of activity signals possible pressure from the industry to expand coal projects as a last ditch effort before China’s 2030 carbon peaking deadline, right when strategic phase-down should be the priority to meet climate goals and as clean energy is meeting all of new power demand growth.

In June 2025, coal’s share in power generation dropped to a nine-year low of 51%, and only made up 34% of China’s total installed capacity, while renewables accounted for 60%, pointing to the ongoing trend of coal losing steam while an artificial push attempts to expand rather than phase down its historic role.

Although China pledged in 2022 that coal should play a flexible, supporting role while renewables are integrated, this policy has yet to be implemented in any meaningful way. Further reform and incentives are needed to transition into scaling down coal power generation and planning a coal exit strategy: in H1 2025, only 1 GW of coal power was retired. 13 GW need to be retired by the end of 2025 to meet the 14th Five-Year Plan goal of retiring 30 GW by the end of 2025. 

With the Nationally Determined Contributions (NDCs) and 15th Five-Year Plan on the horizon, China has a critical opportunity to set binding targets and initiate policy reform that could confirm China’s role as a global leader in the energy transition.

Qi Qin, lead author of the report and China Analyst at CREA: “China’s clean energy boom is driving both economic growth and decarbonisation, but continued coal expansion risks holding it back. More coal power plants would not only waste investment, but also crowd out renewables–the real engine of China’s economic future. To ensure energy security and sustained economic growth, the priority now must be to build a more flexible power system, stop adding new coal power, and set a clear path for coal’s decline.”

Coal power development in China in the first half of 2025 shows no sign of easing, leaving emissions on a high plateau and stranding coal in the system for years to come. To ensure meeting its carbon peaking deadline by the end of the 15th Five-Year Plan period, China must immediately commit to a set of strong policies to phase down coal power development and shut down high-emission and low-efficiency coal units.

Christine Shearer, Research Analyst at Global Energy Monitor

The post Coal is losing ground, but not letting go: Structural inertia and the struggle to shift coal’s role in China’s power system appeared first on Global Energy Monitor.

Despite this reality, an estimated 2,270 Mtpa of new coal mining capacity remains under development. If brought online, this capacity, which represents a quarter of 2024 global production (8,770 Mtpa), could emit an estimated 15.7 million tonnes of methane per year, or around 1.3 billion tonnes of carbon dioxide equivalent (CO₂e) using a 20-year Global Warming Potential (GWP). This would surpass the total annual greenhouse gas emissions of Japan, one of the world’s top ten emitters, which stood at 1.18 billion tonnes in 2022. 

Based on Global Energy Monitor’s (GEM) global survey of active coal mine proposals, key 2024 trends in new coal mine planning include:

• Over 850 new mine plans, mine expansions, and mine extension projects¹ are currently announced or under development worldwide, amounting to 2,270 Mtpa of new capacity. Nearly half of this amount (1,113 Mtpa) is in the early stages of planning and is therefore vulnerable to cancellation. 744 Mtpa is already under construction or in test operation,² while the remaining 414 Mtpa has been approved.
• China, India, Australia, and Russia comprise nearly 90% (1,942 Mtpa) of all proposed mine developments. China alone has 1,350 Mtpa in development — more than all other countries combined.
• In 2024, China saw relatively low levels of both newly-approved coal capacity (57 Mtpa) and new operational capacity coming online (87 Mtpa). However, China still has 1,350 Mtpa of proposed coal capacity at various stages of development. Of this amount, 39% is already under construction or in test operation, 14% has been approved, and the remaining 47% is in early planning, awaiting approval.
• Thermal coal operation plans still dominate, accounting for 75% (1,690 Mtpa) of global proposed mine capacity. However, the opposite is true when zooming in to North America, where metallurgical coal for steelmaking accounts for over 70% of proposed capacity.  
• Three-quarters of mine proposals are “greenfield” developments (1,696 Mtpa), signaling the coal industry’s willingness to break ground on new mines that tend to lock in more long-term production. New mines also lock in more future emissions than existing “brownfield” mines, as well as a higher risk of stranded assets.
• If fully developed, proposed coal mines would emit an estimated 15.7 million tonnes (Mt) of methane annually. Of this, 744 Mtpa of late-stage projects already under construction and in test operation would account for 6 Mt of methane emissions that are effectively locked in. Without strong mitigation measures, proposed coal mining capacity would keep methane emissions well above net-zero targets. 
• Underground mines account for half of all proposed capacity (1,153 Mtpa), but nearly 80% of projected methane emissions. Proposed underground mines are expected to emit 13 Mt/yr, compared to 2.6 Mt/yr from surface mines.

Global overview

Although the rapid expansion of renewable energy over the past decade has helped reduce coal dependence in some countries, it has not kept pace with the surging electricity demand in several major coal-producing nations, such as China, India, and Indonesia, especially in the post-COVID-19 years when global coal production reached record highs. 

During the power shortages of 2021, coal became the immediate fallback solution due to its ease of extraction and stockpiling. This also contributed to the rebound in coal mine operations that year, following two years of slowdown largely triggered by pandemic-related lockdowns and temporary mine closures.

However, in 2024, the amount of production capacity that came online at newly-operating mines hit its lowest level since at least 2015, the year the Paris Agreement was adopted. The 105 Mtpa of added production capacity was over 100 Mtpa below the annual average (206.5 Mtpa) for the 2015 to 2024 period. This decline is largely attributed to top coal-producing countries India and China, however, it doesn’t necessarily signal a sustained downward trend in both countries’ coal expansion plans. Rather, the slowdown likely reflects delays in expansion approvals, the inherently lengthy nature of coal mine development phases, and a potential easing of supply-demand pressure following the pandemic-fueled surge in capacity additions over the previous two years.

Figure 1

Given the substantial amount of proposed capacity still under development, the current downward trend may be at risk of reversing in the coming year.

According to GEM’s latest coal mine data, global coal production capacity has reached at least 8.9 billion tonnes, sufficient to support the record-high output of 8.77 billion tonnes in 2024. Nevertheless, at least 2,270 Mtpa of additional coal mining capacity remains under various stages of development, with a strong focus on the Asia-Pacific region. Developers are pursuing 850 new mines, mine expansions, and mine recommission projects across 30 countries. In addition, 35 mine extension projects are also under consideration.

Figure 2

Nearly 90% of this proposed capacity is located within just a few countries. China leads by a wide margin, accounting for 1,350 Mtpa of proposed capacity, with most projects concentrated in the country’s north and northwest. India follows with 329 Mtpa, nearly half of which is being developed by state-owned Coal India. Australia ranks third with 165 Mtpa, while Russia and South Africa also host significant developments, at approximately 98 Mtpa and 73 Mtpa, respectively.

Map 1

Figure 3

North America has 45 coal mine projects in development, totaling 32 Mtpa, with Canada accounting for two-thirds of this amount, and the U.S. for the remaining one third (11 Mtpa). In the U.S., the current administration’s promotion of so-called “beautiful, clean coal” adds uncertainty to the region’s trajectory toward phasing out coal in the coming years.

Europe has 28 Mtpa of proposed coal mining capacity, with most new coal developments (26 Mtpa) concentrated in Central and Eastern Europe, particularly in non-EU countries like Serbia and Bosnia-Herzegovina.

Indonesia leads Southeast Asia’s coal expansion with 31 Mtpa of new capacity under development, driven by rising domestic demand and thermal coal exports. In South Asia, Pakistan and Bangladesh are advancing coal projects tied to power generation. Beyond Asia, coal development is modest in Central Asia and Latin America, with Kazakhstan leading in Central Asia and Colombia home to all active coal projects in Latin America.

Among the proposed projects, approximately three-fourths — representing around 1,696 Mtpa of capacity — are “greenfield” or brand new developments. This highlights the coal industry’s continued push to open new mines. Once developed, greenfield projects tend to lock in long-term future emissions, with an average reported mine life of approximately 54 years longer than that of brownfield projects (31 years), according to GEM’s latest coal mine data. These new developments also carry a higher risk of becoming stranded assets if coal demand declines or prices fall, potentially rendering them uneconomical and leading to idling or abandonment.

Country / Regional analysis

China

As of April 2025, China maintained a total of 1,350 Mtpa of proposed coal mine projects (including expansions), accounting for 60% of the global proposed capacity. This amount surpasses the combined operating coal capacity of Indonesia and Australia, the world’s third- and fourth-largest coal producers.

Over one-third (39%) of China’s proposed capacity is already under construction or in test operation, while 14% has been approved, and nearly half (47%) remains in the early stages of planning or development.

Proposed projects are primarily concentrated in five provinces and autonomous regions — Inner Mongolia, Shaanxi, Xinjiang, Guizhou, and Shanxi — accounting for 89% of the total proposed capacity. Inner Mongolia stands out as the leading province in proposed coal mine development, with approximately 41% of its total project capacity already under construction or in test operation.

Figure 4

China’s coal mine capacity approvals peaked in 2019 after the 2016 launch of its de-capacity policy, then declined sharply through 2020–2021, hitting a multi-year low of 32 Mtpa in 2021. However, following the power shortage crisis in the second half of 2021, China responded by rapidly expanding existing production capacity and accelerating approvals of new and expanded mines. As a result, approvals surged in 2022, reaching 90 Mtpa of capacity — nearly triple that of 2021. However, as coal supply shortages eased, this rapid expansion gradually lost momentum, with the total approved capacity dropping to 57 Mtpa in 2024, a 33% decline from 2023 and the lowest in three years. In 2024, China commissioned 87 Mtpa of new coal mine capacity, representing a 38% year-on-year decline and marking the lowest level in the past decade.

While this may suggest a downward trend in new operational capacity, it remains too early to confirm such a shift. Given that coal mine construction typically takes 3–5 years, the 2024 decline may instead reflect the lagging effect of fewer approvals in 2020 and 2021. By this same respect, the large volume of projects (233 Mtpa) approved during 2022–2024 is likely to be commissioned in the coming years, potentially contributing to a new wave of capacity growth.

Figure 5

More crucially, the development of proposed projects continues to receive policy support in China. China unveiled a plan in 2024 to establish a coal capacity reserve system by 2027, which aims to enhance energy security by ensuring more flexible coal supply. This indicates that additional capacity will likely be brought under development, since the plan involves approving a batch of coal mines specifically designated for reserve purposes. By 2030, the country aims to establish approximately 300 Mtpa of dispatchable reserve capacity.³

For these reserve coal mines, 60% or more of their new capacity is exempt from the standard capacity replacement requirement (coal enterprises must retire outdated or inefficient coal production capacity before gaining approval to develop new, more advanced coal mines) established in 2016 for capacity reduction. According to some estimates, the net increase in newly-built capacity by 2030 is expected to reach up to 1.3 billion tons, or the equivalent of roughly one-quarter of China’s 2024 total coal output, because of this policy support.

The National Energy Administration’s 2025 Energy Work Guidance calls for approval of a new batch of large-scale, modern coal mines and acceleration of construction for already approved projects. 

For example, Inner Mongolia, which leads in renewable energy development, also holds the largest volume of proposed coal mining capacity and has reportedly accelerated coal mine construction in 2025. Approximately 31.5 Mt of capacity is currently in the test operation phase, while another 8.6 Mt is expected to complete construction by the end of the year. Additionally, eight projects that fall under the coal capacity reserve system category have been approved, with a total production capacity of 92 Mtpa, including a reserve capacity of 16.4 Mtpa.

China’s coal production has grown for four consecutive years since the 2021 power crisis. In 2024, domestic coal output reached 4,780 Mt, up 1.2% year-on-year, while coal imports rose 14.4% to 542.7 Mt. The combination of robust domestic production and growing imports has shifted China’s coal supply from tight to relatively abundant.

Although coal consumption reached 4,890 Mt in 2024 — a 1.7% increase — the growth rate has slowed over the past three years, and data from the first quarter of 2025 also indicates an overall downward trend.

Among China’s four major coal-consuming industries (power generation, steel production, construction materials manufacturing, and chemicals manufacturing), the power sector consumed 2,870 Mt of coal in 2024, marking a 1.2% year-on-year increase. However, with the rapid expansion of renewable energy, demand for coal in this sector is expected to decline gradually in the future. The production of steel and cement faces overcapacity and declining demand in 2024. However, coal consumption in the coal-to-chemicals sector reached 319 Mt in 2024, representing a 7% year-over-year increase. Although its share remains insignificant relative to other key sectors of coal demand, future annual growth is projected to stay in the 5%–10% range, making it the only sector among the four major coal-consuming industries expected to continue growing.

Among the proposed projects, 47% (635 Mt) remained unapproved and is still in the planning or early project stages. If these plans are not significantly rolled back in the forthcoming 15th Five-Year Plan⁴ (2026–2030), China could see a new wave of coal capacity coming online, potentially leading to another round of overcapacity similar to that experienced during 2012–2015.

India

India ranks a distant second globally in proposed coal mining capacity, with 329 Mtpa currently under development. Of this, 163 Mtpa remains in the early planning stage, approximately 90 Mtpa has been permitted, and 75 Mtpa is already under construction. The pipeline is geographically concentrated in four states, with Jharkhand (106 Mtpa), Odisha (92 Mtpa), Chhattisgarh (50 Mtpa), and Madhya Pradesh (44 Mtpa) accounting for nearly 90% of the total proposed capacity of the country.

Figure 6

India’s coal sector is dominated by state-owned enterprises (SOEs), which are responsible for approximately 72% (238 Mtpa) of the proposed mining capacity. Coal India alone accounts for 139 Mtpa, making it the leading player in India’s coal expansion. Other SOEs include Singareni Collieries (16 Mtpa) and lignite-focused NLC India Ltd (26 Mtpa).

Private developers are also playing a significant role, planning 92 Mtpa of additional proposed capacity. The Adani Group, India’s largest privately-owned coal developer and the country’s leading mine developer and operator (MDO), holds 28 Mtpa. Vedanta Ltd follows with 18 Mtpa, making it the second-largest private coal mining company with proposed capacity in development within the country.

Coal production in India has risen steadily, reaching a record 1,048 Mt in FY 2024–25. This growth is expected to continue as the government pushes to boost domestic output, aiming to reduce import reliance and allegedly improve energy security. The government targets 1.3 billion tonnes of coal production by FY 2027 and 1.5 billion tonnes by 2030. To support this goal, India plans to open 100 new coal mines, adding 500 Mtpa in capacity by 2030. Over 80 Mtpa is expected to come online in FY 2025–26, suggesting that already permitted or under-construction projects could be fast-tracked.

Coal continues to be a cornerstone of India’s economy, powering critical sectors such as electricity, steel, and cement. However, domestic reserves of metallurgical or coking coal and high-grade thermal coal are limited, making imports, especially for steelmaking, essential. At present, metallurgical coal accounts for only about 3% of the country’s proposed coal mining capacity.

To address this gap, the Ministry of Coal has launched Mission Coking Coal, aiming to increase domestic coking coal production to 149 Mt by FY 2029–30. This is expected to spur a wave of new metallurgical coal projects in the future.

Meanwhile, underground mining, which currently makes up less than 10% of India’s coal production, is also a focus area. The government has set a target to produce 100 Mt from underground mines by 2030 to boost overall domestic coal supply. Yet, current proposals only include about 20 Mtpa (6% of the pipeline), indicating that additional underground projects could be added to the pipeline in the future.

The government’s latest Action Plan also highlights “unlocking the value of discontinued mines” as a key strategy for meeting short-term goals. In June 2024, Coal India announced plans to reopen over 30 previously uneconomic mines, 27 of which have already been awarded through tenders. This initiative is expected to contribute significantly to near-term production increases.

Australia and New Zealand

Australia ranks third after China and India in terms of proposed coal mining capacity under development, accounting for roughly 7% of global proposals, with a total of 165 Mtpa in various stages. Of this total, 96 Mtpa has already received approval and is under construction, while the remaining 70 Mtpa is still in the early planning phase. As with its current coal production, the bulk of proposed capacity is concentrated in Queensland and New South Wales, two major coal-producing states in Australia which host approximately 124 Mtpa and 41 Mtpa of proposed capacity, respectively.

Australia is the world’s leading exporter of metallurgical coal, with about 89% of its metallurgical coal product exported in 2022–2023. The country now accounts for roughly one-third (58 Mtpa) of the world’s proposed metallurgical coal mining capacity, most of which is clustered in Queensland. China, once a top buyer of Australian coal, lifted its import restrictions in early 2023. However, Mongolia emerged as China’s second-largest source of metallurgical coal in 2024, reducing China’s reliance on Australian exports. Although Australia still supplies over half of India’s metallurgical or coking coal imports, India plans to ramp up domestic production and acquire overseas assets as part of its “Mission Coking Coal,” potentially diminishing future demand for Australian imports. This creates a risk that early-stage metallurgical coal projects in Australia may be shelved or cancelled due to declining international demand.

On the domestic front, coal use in power generation — which accounts for about 88% of Australia’s total coal consumption — has been declining in recent years. Nonetheless, significant thermal coal capacity remains in the pipeline, with 85 Mtpa in proposed thermal coal projects and an additional 15 Mtpa in mixed thermal-metallurgical projects. This comes despite Australia signing a call for no new coal plants in national climate plans at COP29 and appearing on track to significantly reduce coal use. The country already has sufficient existing thermal capacity of 230 Mtpa, while coal consumption in 2023 totaled only 1.5 exajoules (approximately 62.5 Mt), a figure that reflects the ongoing shift away from coal in electricity generation, largely driven by a rapid increase in solar energy production. In light of these factors, many of the proposed thermal coal projects may face a risk of becoming stranded assets. 

Although New Zealand has no new coal mining capacity proposed, coal development has not come to a halt. Instead, there are around six proposals to extend the lifespan of existing operations, all submitted by the country’s leading coal producer, Bathurst Resources. This includes the Stockton Coal Mine, New Zealand’s largest mine, which is set to expire in March 2027 but could continue producing coking coal for another 25 years if the extension is approved.

Russia

Russia has approximately 98 Mtpa of proposed coal mining capacity, ranking fourth globally. This includes 30 Mtpa already under construction and another 15 Mtpa undergoing test operations prior to entering full commercial production. An additional 23 Mtpa has received permits and risks advancing to the construction phase, while the remaining 30 Mtpa is still in early planning.

Geographically, nearly half of this proposed capacity is concentrated in three key federal subjects — Kemerovo, Sakha (Yakutia), and Krasnoyarsk — which align with Russia’s major coal basins. The Amur and Novosibirsk regions each account for around 10 Mtpa of proposed development.

Around half of Russia’s coal production is exported, now primarily to eastern markets, following the European Union’s ban on Russian coal imports in response to the 2022 invasion of Ukraine. Although Russian coal exports have declined in recent years, driven by sanctions and efforts among key buyers to diversify supply and strengthen domestic production, there is little indication that Russia is slowing its coal mine development. On the contrary, the country’s coal sector is aiming to boost annual production to over 600 Mt by 2050, up from the current 440 Mt, and to secure a quarter of the global coal market by increasing coal exports to 350 Mt by 2050. This is a significant increase from the export levels of less than 200 Mt in 2024, as outlined in the Russian Federation’s Energy Strategy to 2050. Achieving these ambitions will largely depend on the exploration and expansion of new coal mining clusters.

South Africa and the African continent

Africa is home to 5% (121 Mtpa) of the world’s proposed coal mine capacity. Nearly two-thirds (73 Mtpa) of this amount is concentrated in South Africa, with the remaining planned capacity located in Mozambique (34 Mtpa), Botswana (9 Mtpa), Tanzania (4 Mtpa), and Niger (1 Mtpa).  

South Africa has 35 proposed coal mines with a projected output of 73 Mtpa, ranking fifth globally, just behind Russia, in proposed coal capacity. Of these 35 projects, 21 are planned for the Mpumalanga province, which is already responsible for 83% of South Africa’s coal production. Six of the remaining fourteen projects are located in KwaZulu-Natal; five are in Limpopo; two are in Gautang; and one is planned for the Free State. Nearly 80% of South Africa’s proposals are for thermal coal, which is largely used for domestic power generation.  

Mozambique’s 34 Mtpa of proposed coal capacity is roughly triple its actual 2023 coal production (11 Mt). If all of this capacity were to come online, it would represent one of the largest percent shifts in national output worldwide. The bulk of this capacity consists of the 12-Mtpa multi-phase expansion of the Benga coal mine and the 8-Mtpa expansion of its Chirodzi coal mine, both owned by India-based Jindal Steel. In recent years, Mozambique — whose primary export is coal — has strived to attract foreign investment to develop its vast natural resources, including coal, in the hopes that the move will facilitate the country’s economic independence.

All of Botswana’s 9 Mtpa of coal capacity is currently under construction with plans to come online in the next 1–2 years.

The planned coal mining capacity in Tanzania is for two coal projects, one of which is a joint venture project between the Tanzanian government and China’s Sichuan Hongda to supply coal to the Mchuchuma power station. In Niger, the 1 Mtpa Salkadamna coal mine is planned as a companion mine to the proposed Salkadamna coal plant, whose plans have stalled for over a decade. 

While GEM is also tracking a few planned coal mining projects in Eswatini, Madagascar, and Zimbabwe, the details of each, including coal capacity, are at present unclear.

North America

North America has 45 mine projects in development, amounting to 32 Mtpa of proposed new capacity. Two-thirds of this proposed capacity (21 Mtpa) is concentrated in Canada. While Australia is the world’s leading producer of metallurgical coal, North America is leading the shift from thermal to met coal production, as evidenced by the fact that met proposals in the U.S. and Canada now outweigh those for thermal operations by 68% and 77%, respectively.

In 2024, U.S. coal production continued its decades-long decline, falling to 512 million short tonnes as competition from gas and renewables in the electric power generation arena has increased. U.S. coal prices have been declining too, falling to 2021 levels at the close of the year. As a result, many coal producers are hesitant about scaling up too quickly. This is reflected by the fact that only 11 Mtpa of coal capacity is planned, with most located in West Virginia.

In addition to being modest with their mine proposals, another way U.S. coal companies are attempting to weather this coal slump is by lowering costs. For example, through their recent merger, Arch Resources and CONSOL Energy aim to shave off as much as US$140 million in annual operational costs.

It’s still too early to tell how the second term of the Trump administration will impact U.S. coal’s downward trend. The U.S. government has declared a national energy emergency and intends to boost America’s fossil fuel production. In an effort to push this new “pro-coal” sentiment, the U.S. government has made several goodwill gestures to coal companies, including approving the decades-long proposed expansions of the Spring Creek mine and Bull Mountains mine in Montana, and expediting the environmental permitting process of new coal projects. However, as of May 2025⁵, few coal producers have made public-facing changes to their 2025 strategic plans. This suggests a lingering hesitancy about continued poor market conditions and economic uncertainty caused by the Trump administration’s shifting tariff and trade policies, which could prove detrimental to the coal export market.

Meanwhile, U.S. producers attempt to continue protecting themselves by increasing investments in new metallurgical mines. All but two proposed mines are planned by top metallurgical coal companies Ramaco Resources, Coronado, Alpha Metallurgical, and Warrior Met. This trend is expected to continue in 2025, especially given the recent designation of metallurgical coal as a “critical material” by the U.S. Energy Department.

Similarly, Canadian operators have readily embraced a supposed revival of metallurgical production, which is not affected by shifts in power generation. As of 2024, 77% (17 Mtpa) of Canada’s proposed coal mines are metallurgical projects, most located in British Columbia where the coal fields are rich in coking coal.

While some companies are turning to metallurgical coal during the clean energy shift, others are taking the opportunity to divest from coal altogether. In 2024, Vancouver-based Teck Resources, which was once the largest metallurgical coal producer in North America, finalized the sale of its metallurgical coal assets to Glencore. This comes despite Glencore’s renewed pledge to its 2050 net-zero emissions goal.

Europe

Europe’s combined 28 Mtpa of proposed coal capacity ranks it among the regions with the most modest proposed coal mining capacity globally. Coal production continued to plummet in Europe, with several countries, including the UK and Slovakia, completing their coal phaseout plans, and mine operators facing declining demand from power companies due to competition from wind, solar, and gas.

As of October 2024, the UK has successfully phased out coal power generation, becoming the world’s first major economy, and the sixth country, to eliminate coal from its power grid. Despite no longer using coal for power generation, the UK still has three mine proposals in consideration whose coal would be used for steelworks — the under 1 Mtpa expansion of the Aberpergwm Coal Mine, the 1.2 Mtpa Lochinvar coal mine, and Energy Recovery Investments’ controversial project to extract so-called “reclaimed” coal from coal tips at the retired Bedwas Colliery.

Elsewhere across Europe, coal has proven more difficult to dislodge. As of 2024, the Western Balkans has ten coal mine projects, amounting to 20 Mtpa of new mine capacity, with half in early phase developments and the other half under construction. Serbia, which has five new mine proposals amounting to 15 Mtpa, leads the coal expansion. It is followed by Bosnia-Herzgovina (3.5 Mtpa) and North Macedonia (1 Mtpa), which have two new mine proposals each, and Montenegro (under 1 Mtpa). Romania (5 Mtpa) is the only country within the European Union proposing new coal. And in Ukraine, the 1 Mtpa Novovolynskaya No 10 coal mine, whose construction began decades ago, remains planned but stalled.

Neither Germany nor Poland have any coal mining capacity in the pipeline, which aligns with each country’s 2038 and 2049 respective coal phaseout targets (though both timelines are widely seen as needing to be brought forward to meet climate commitments).

Other Asian countries

Outside of China and India, approximately 135 Mt of proposed coal mining capacity is in the pipeline across twelve Asian countries, with Pakistan and Indonesia together accounting for more than half of this total.

Figure 7

Southeast Asia’s coal development pipeline is led by Indonesia, which currently has 15 Mtpa of coal mining capacity under construction and an additional 16 Mtpa in early-stage planning. Indonesia’s coal production has grown steadily in recent years, rising from 564 Mt in 2020 to 836 Mt in 2024. This increase has been driven by expanding domestic power demand and surging imports from countries like China, India, and other regional buyers. At present, Indonesia is developing at least 31 Mtpa of new coal mining capacity, 94% of which is thermal coal aimed at supplying both domestic power generation and international markets. Additionally, more than 40 proposed coal mine projects remain at very early stages and lack reported capacity data.

The country’s coal resources are heavily concentrated on Kalimantan Island, particularly across the provinces of South, East, Central, West, and North Kalimantan. This region accounts for over 80% of Indonesia’s coal output and hosts more than half of the proposed capacity (approximately 20 Mtpa), with South and East Kalimantan leading in project scale.

Roughly 84% of Indonesia’s known coal reserves are low- to medium-grade thermal coal primarily used for power generation, making the country the leading thermal coal exporter in the world. However, the country is also a metallurgical coal importer, sourcing coking coal mainly from Russia, Australia, and China. While nearly all proposed mining capacity is focused on thermal coal, the Indonesian government has recently ramped up exploration efforts to identify new coking coal deposits and reduce its reliance on imports.

With China and India purchasing nearly two-thirds of Indonesia’s coal exports in 2023, the country’s coal mining sector faces significant exposure to the risk of uneconomic and stranded assets. This vulnerability became apparent in early 2025, when Indonesia’s thermal coal exports fell to a three-year low between January and April, driven by reduced demand from both countries as they’ve taken efforts to boost domestic production to lower import dependence.

Beyond Indonesia, the Philippines holds 8 Mtpa of proposed coal mining capacity in Southeast Asia, all of which remains in early-stage development without permits. 

Pakistan ranks second in South Asia, after India, with approximately 38 Mtpa of coal mining capacity under development. Most of these proposed projects are tied to coal demand from the power sector. For example, the Thar Block VI open-pit project is planned in two phases: Phase 1 includes the development of 7.9 Mtpa of capacity alongside a 1,320 megawatt (MW) mine-mouth power plant, while Phase 2 involves expanding the mine by an additional 8.1 Mtpa to support a coal gasification and coal-to-liquid facility operating in parallel with the power plant. At Thar Block II, Phase III is in the pipeline, targeting an additional 3.8 Mtpa to supplement the existing 7.6 Mtpa of operational capacity. This expansion has already been permitted. In a 2024 interview, the company of Thar Block II has confirmed that Phase IV is under planning, with the long-term goal of increasing total production at Thar Block II to approximately 30 Mtpa.

Bangladesh currently has a very small coal production capacity, less than 1 Mtpa, yet it ranks third in South Asia in terms of proposed coal mining capacity, with around 10 Mtpa under development. Coal plays a relatively minor role in the country’s energy mix compared with other energy sources like gas, oil, and biofuels, accounting for just 5.5% of total energy supply. At present, only one coal mine, the Barapukuria Coal Mine, is operational, with a production capacity of 0.9 Mtpa.

Since 2020, Bangladesh has begun importing coal to fuel the Payra power station, and coal consumption is projected to rise through 2030 in the government’s 2023 Integrated Energy and Power Master Plan. Developing new domestic coal mines is seen as a strategy to reduce reliance on imported coal and ensure a stable local supply. Additionally, as the country transitions away from traditional biomass — still a major energy source — toward fossil fuels like coal, this may further justify plans for expanding mining capacity.

However, all currently proposed coal mines remain in the early planning phase. Bangladesh pledged at COP26 in 2021 to aim for up to 40% clean energy in its power generation mix by 2041. If this target is reached ahead of schedule, national coal demand could peak and begin to decline earlier than expected, potentially rendering much of the proposed mining capacity unnecessary.

Coal development is also active in Central Asia, with Kazakhstan leading the region at approximately 17 Mt of proposed coal mining capacity, nearly 60% of which is nearing completion. As one of the top ten countries with the largest proven coal reserves, Kazakhstan is proposing new coal-fired power plant construction which would boost domestic demand for coal. At the same time, it is seeking to diversify coal exports abroad; currently, about one-third of Kazakhstan’s coal is exported, primarily to Russia, the EU, and Asian markets.

Meanwhile, Uzbekistan, Kyrgyzstan, and Tajikistan collectively have 11 Mt of proposed capacity, though most projects remain in early, unpermitted stages.

Latin America

Latin America accounts for a mere 0.5% (12 Mtpa) of proposed global coal mining capacity. Only one country, Colombia, is home to all coal mine projects currently under development.

Colombia’s three largest coal mine projects currently under consideration include the San Juan mine (with an estimated average annual production of up to 10.5 Mtpa), the Cañaverales Coal mine (up to 0.8 Mtpa), and the Papayal mine (up to 0.9 Mtpa) — all owned by Turkish multinational firm, Yildirim, through its Colombian subsidiary Best Coal Company. While transparency issues continue to surround Yildirim’s plans for the mines, their coal is expected to be imported to Türkiye for power generation.

2024 marked the second anniversary since Brazil’s proposed Guaíba mine was shelved. Had the 5 Mtpa mine been approved and built by private coal mining company Copelmi Mineração, it would have been inundated by over 28 inches (700 mm) of rain which fell across the Porto Alegre region during the 2024 Southern Brazil floods. This near miss is a stark reminder of coal’s cascading environmental impacts beyond the release of heat-trapping greenhouse gases.

Mine proposals: Lock in of future coal mine methane emissions

A projected 15.7 Mt of methane emissions per year could be released if all globally proposed coal mining projects are developed.⁶ This is equivalent to roughly 1.3 billion tonnes of CO₂e using a 20-year Global Warming Potential — exceeding Japan’s total annual greenhouse gas emissions, which stood at 1.18 billion tonnes in 2022. Should all this capacity become operational, global coal mine methane emissions could rise by approximately 39% over the IEA’s latest estimate of 40.3 Mt, and by approximately 26% compared to GEM’s latest estimate of 58.9 Mt from currently operating mines — an estimate that does not account for any mitigation measures.

Without robust abatement, emissions from new coal mines would compound the already significant methane emissions from existing mines. Altogether, these emissions would add up to over 6 billion tonnes of CO₂e (20-year GWP), comparable to the annual greenhouse gas emissions of the United States, the world’s second-largest emitter at 6.02 billion tonnes in 2022.

Figure 8

Currently, over 850 new coal mines or mine expansions of varying capacities are under development worldwide. Of these, 296 projects are under construction and expected to become operational within the next few years, while 28 mines are in the test operation phase and likely to start full production within a year. Together, these late-stage developments represent a total of 744 Mtpa in new capacity and are projected to emit around 6 Mt of methane annually, once operational. 

An additional 186 projects, representing approximately 414 Mtpa of coal mining capacity, have already received permits. These permitted projects, currently in the interim phase of development, are expected to generate 2.9 Mt of methane annually unless halted or abandoned. 

The remaining 1,113 Mtpa of coal mining capacity, linked to estimated methane emissions of at least 6.9 Mt/yr, remains in early development stages, including announcement, exploration, and pre-permitting. These projects are particularly susceptible to delays, or may ultimately be shelved or canceled altogether, depending on shifts in coal demand as well as economic, environmental, social, and climate risks across different countries.

Figure 9

China is the source of the largest projected increase in global coal mine methane emissions, accounting for 80% of estimated emissions from proposed projects worldwide. The country has 456 proposed coal mines under development, totaling approximately 1,350 Mtpa in planned capacity. If fully realized, these projects could emit an additional 12.6 Mt of methane annually, according to GEM estimates. With nearly 40% of this capacity already under construction or in test operation, about 5 Mt of new emissions per year may be effectively locked in.

Australia follows, with 58 proposed projects, totaling 165 Mtpa, that could add up to 0.8 Mt of methane per year. Of this amount, 14 Mtpa is currently under construction, locking in an estimated 0.1 Mt/yr, while another 82 Mtpa has been permitted and could contribute 0.4 Mt annually, if developed.

Russia ranks third, with 36 proposed coal mines totaling 98 Mtpa and the potential to release 0.6 Mt of methane annually. Projects already in advanced stages account for 0.2 Mt/yr, with an additional 0.2 Mt/yr likely from 23 Mtpa of permitted capacity. Combined, China, Australia, and Russia account for nearly 90% of the projected methane emissions from proposed coal mine developments worldwide. 

India ranks fourth in projected methane emissions from proposed coal mining capacity, with an estimated 0.43 Mt of methane emitted annually, nearly 90% of which comes from identified thermal coal projects. With the government aiming for a significant expansion of domestic coal production, particularly from underground and metallurgical coal mines by 2030, methane emissions are likely to increase further in the absence of effective abatement measures.

From a coal grade perspective, proposed thermal coal mines, primarily intended for power generation, are projected to release approximately 11.5 Mt of methane annually. In contrast, proposed metallurgical coal mines, which serve steelmaking and other industrial processes, are expected to emit around 1.7 Mt, based on GEM’s analysis of proposals with identified coal grade information. While the overall emissions from metallurgical projects appear smaller due to a much smaller number of mines and total capacity, they tend to be significantly more methane-intensive on a per mine basis. On average, metallurgical coal mines emit 2.5 times more methane than thermal mines of comparable size. This is largely because metallurgical projects are often deep underground operations targeting higher-rank coal types such as bituminous and anthracite, where methane concentrations increase with depth.

Figure 10

China, without doubt, dominates emissions across all coal grades, largely due to its unmatched volume of proposed coal mining capacity across various coal ranks. Outside of China, Australia is the second-largest emitter from proposed coal projects, with over two-thirds of its projected emissions coming from metallurgical coal capacity. Russia and Canada follow as the next largest emitters from metallurgical coal proposals.

From a coal mine type perspective, underground mines are typically more methane-intensive than surface mines. Proposed underground coal mine projects are projected to emit approximately 13 Mt of methane annually, compared to 2.6 Mt/yr from surface mine projects. China hosts the largest share of proposed underground coal mining capacity, accounting for 88%. While Australia has a much smaller share compared with China, it still ranks second with 4% of total projected emissions from underground proposals.

Although projected emissions from proposed surface mines are generally lower than those from underground mines, this does not make them any less significant. GEM’s analysis finds that several proposed surface mines with large production capacities could emit more methane annually than many underground mines. A notable example includes the Changtan Surface Coal Mine in China. If developed, this project could emit between 5.3–14.6 Mt CO₂e (based on 100-year and 20-year GWPs) per year, placing it among the largest methane-emitting coal mines in the world.

Emissions from surface or open-pit coal mining have often been overlooked due to their comparatively smaller share. However, aircraft-based measurements have shown that methane emissions from a major open-pit coal mine in Australia were three to eight times higher than reported. Without sufficient attention and more direct measurement data, methane emissions from surface mines risk becoming the overlooked “elephant in the room” in global coal mine methane accounting.

How proposals impact global emissions targets

Greenhouse gas emissions have reached an all-time high, making the scale of required reductions even more daunting. With a substantial volume of coal mining capacity still in the development pipeline, moving forward with these projects would only move progress further away from achieving global climate targets.

According to the United Nations Environment Programme’s (UNEP’s) Production Gap Report 2023, achieving the 1.5°C target under the low demand (IMP-LD) scenario requires a massive 75% reduction in coal production by 2030 compared to 2020, meaning global output would need to drop from about 7,607 Mt in 2020 to just 1,902 Mt — or roughly 571 Mt per year — by 2030. However, with global coal production having reached 8,770 Mt in 2024, the required cuts have doubled to about 1,144 Mt per year in order to remain aligned with the 1.5°C target (see Figure 11, dark-green line).

In comparison, the IEA Net Zero Emissions (NZE) scenario offers a more gradual approach, projecting a 39% reduction in coal production from 2020 levels, down to roughly 4,640 Mt by 2030. Yet even this slower pathway, which originally required an average reduction of about 297 Mt per year, now demands cuts of 688 Mt per year (Figure 11, light-green line).

However, if all 2,270 Mtpa of proposed coal mining capacity (Figure 11, dark-red bars) is developed and brought online at a steady rate through 2030 (averaging 378 Mtpa annually) — even after accounting for production at mines slated for closure or expected to deplete their recoverable reserves before 2030 (totaling 837 Mtpa) — the gap between current production trends and what’s required to achieve climate targets will widen further. This scenario would necessitate even more aggressive cuts, requiring annual retirements of coal mining capacity to not only match but exceed the pace of new additions in order to stay on track for the 1.5°C target under both the UNEP and IEA NZE scenarios.

Figure 11

From an emissions perspective, the IEA’s NZE scenario calls for methane emissions from coal production to be cut by around 75% from today’s levels by 2030 — dropping from 40.3 Mt in 2024 to just 10 Mt by 2030. This requires an average annual reduction of approximately 5 Mt, totaling about 30 Mt over the next five years to stay on track for the NZE target. With annual methane emissions still showing no downward trend, and the time frame narrowing, the path to achieving this goal is becoming increasingly precarious.

If all 2,270 Mtpa of proposed coal mining capacity is developed and brought online at a steady rate through 2030, over 15 Mt of additional methane emissions are projected each year (see Figure 12, dark-red bars). Without strong mitigation measures, these new projects would further jeopardize progress toward net zero.

Figure 12

The IEA’s updated Net Zero Roadmap, which charts a path to limiting global warming to 1.5°C by 2050, calls for no new coal mines or mine extensions under the NZE scenario. Developing new greenfield coal projects risks not only creating stranded assets, but also locking in costly, long-term emissions. Rather than expanding production capacity or extending the lifespan of existing (“brownfield”) mines, these sites should be evaluated for potential conversion to renewable energy use, such as solar power projects.

Out of the 30 countries with coal mining capacity still under development, 21 are signatories to the Global Methane Pledge. Together, these countries’ proposed projects are expected to emit nearly 2 Mt of methane annually. Yet, to date, only a limited number of countries and regions have submitted detailed methane action plans. If countries are truly committed to meeting their climate targets, the solution is not to pursue further coal mine development with uncertain mitigation measures but to halt new projects entirely. The most effective strategy forward remains clear: Leave coal in the ground.

¹ Extension projects refer to existing mines seeking to prolong their lifespan by mining new areas without increasing current production rates. 

²In China, “test operation” denotes the phase prior to commercial launch in which the mine completes construction, commissions equipment, conducts safety and operational checks, and initiates limited production to ensure readiness for full-scale output. This process is also observed in Russia and Kazakhstan.

³Coal production reserve mines adopt a “base + reserve” dual-capacity system, with reserve capacity accounting for 20%–30% of total output. Under normal conditions, only base capacity operates, while reserve capacity can be quickly activated during emergencies.

⁴China’s Five-Year Plan is a national economic and development blueprint released every five years outlining major policy goals and priorities.

⁵The May version of the GCMT dataset was updated in July, featuring major revisions to the “Parent Company” column, which now reflects GEM’s latest ownership format and includes associated Entity IDs for parent companies (excluding Chinese companies), along with other minor changes. Please visit the download page for the updated version.

⁶For further detail on estimating methane emissions from coal mines, visit GEM’s methodological wiki page.

About the Global Coal Mine Tracker

The Global Coal Mine Tracker is a worldwide dataset of coal mines and proposed projects. The tracker provides asset-level details on ownership structure, development stage and status, coal type, capacity, production, workforce size, reserves and resources, methane emissions, geolocation, and over 30 other categories. 

The most recent release of this data in May 2025 includes operating mines producing 1 million tonnes per annum (Mtpa) or more, with smaller mines included at discretion. The tracker also includes proposed coal mines and mine expansions with various designed capacities.

Media Contact

Dorothy Mei

Project Manager, Global Coal Mine Tracker

dorothy.mei@globalenergymonitor.org

The post Still digging 2025: Tracking global coal mine proposals appeared first on Global Energy Monitor.

China is advancing a nearly 1.3 terawatt (TW) pipeline of utility-scale solar and wind capacity, leading the global effort in renewable energy buildout. This is in addition to China’s already operating 1.4 TW of solar and wind capacity, nearly 10% of which (141 gigawatts (GW)) came online in 2024. Though only a small portion of China’s overall renewable capacity, China’s offshore wind fleet contributes over 50% of the overall offshore wind capacity in construction worldwide. However, China is not immune to the challenges of this new market, as development of offshore wind in China has slowed in recent years. In order for this technology to advance, China has an opportunity to move from its provincial development approach to one that provides stable and market-specific national policies.

• China is fast-tracking a 1.3 TW pipeline of utility-scale solar and wind projects. Of this, 510 GW is already under construction, primed to be added to China’s 1.4 TW solar and wind capacity already in operation.
• As of March 2025, China has emerged as the world’s offshore wind powerhouse — growing from under 5 GW in 2018 to 42.7 GW in 2025 (50% of global capacity).
• Offshore wind could play a role in decarbonizing China’s coastal provinces, but fossil fuels stand in the way. 
• China’s offshore wind fleet shows promising expansion as technology and development progress, but international policies can provide valuable insights for national strategies to ensure market stabilization. 

China has over 1.3 TW of planned solar and wind capacity

China leads global utility-scale solar capacity for projects in announced, pre-construction, and construction phases. According to Global Energy Monitor’s Global Solar Power Tracker, China has over 709 GW¹ of prospective solar capacity, representing over one-third of planned solar capacity worldwide in 2025. These projects could generate approximately 1,100 terawatt hours (TWh) of electricity per year — equivalent to roughly 122% of Japan’s 2023 electricity consumption (909 TWh). About 161 GW (23%) of prospective capacity is in announced phases, while 261 GW (37%) is in pre-construction phases. China’s construction capacity exceeds 40%, as 287 GW has broken ground. This is roughly four times the global average for capacity under construction (9%).

Figure 1

China’s wind capacity follows a similar rate of growth as solar, according to Global Energy Monitor’s Global Wind Power Tracker, with over 590 GW in prospective phases — nearly 530 GW of onshore capacity and 63 GW of offshore capacity. As of July 2025, 223 GW (37%) of this prospective capacity is under construction, almost four times the combined under-construction capacity of the rest of the world. If these projects become operational, they could generate roughly 1,260 TWh of electricity per year, enough to power about 120 million United States households. Ultimately, China’s prospective capacity accounts for about one-third of total global wind capacity in development.

Geographically, Xinjiang and Inner Mongolia host 40% (523 GW) of China’s prospective capacity. Of this, nearly 212 GW — 31% of global utility-scale solar and wind under construction — is found in these autonomous regions. This rapid buildout underscores China’s drive to accelerate its renewable energy development, with at least 205 GW of new capacity slated to come online in China by this year’s end, though the total capacity is expected to be even higher.

Figure 2

China’s 1.4 TW operating solar and wind outstrips thermal power 

In Q1 2025, China’s wind and solar capacity surpassed its thermal (coal and gas) capacity for the first time, supplying nearly 23% of the country’s total electricity consumed, up from roughly 18% in Q1 of 2024, according to the National Energy Administration (NEA). Increased output from solar, wind, and other non-fossil energy also met China’s additional electricity demands in Q1 2025. China’s solar and wind operating capacity has soared to 1.4 TW and now accounts for 44% of the world’s operating utility-scale solar and wind capacity, more than the combined total of the European Union, United States, and India.

As of May 2025, China has installed 1,080 GW of solar capacity, with May seeing China’s  largest monthly increase in operating capacity. China’s annual solar additions jumped from 55 GW in 2021 to 88 GW in 2022 (+60%), surged to 216 GW in 2023 (+145%), and then reached 278 GW in 2024 (+29%). Of the 278 GW added capacity, 57% (159 GW) came from centralized installations and 43% (118 GW) came from distributed systems. Included in 2024 additions is the world’s largest single-site photovoltaic plant — the 3.5 GW Midong Solar Farm, located in Xinjiang Autonomous Region — which was connected to the grid in June 2024. Once fully operational, the solar project Midong is expected to generate nearly 6.1 TWh per year, nearly matching the annual electricity demand of Luxembourg in 2023.

Figure 3

Wind power has followed a similarly rapid trajectory. As of May 2025, China added 46 GW of new wind capacity for the year, bringing the total to 570 GW of operating capacity. A notable project is the Omattingga Wind Farm in Tibet, a 100 megawatt (MW) installation that is the world’s highest-altitude wind farm. At 4,650 meters high, it produces about 200 gigawatt hours (GWh) annually.

Figure 4

Offshore wind development ramping up in China

China’s coastal provinces² are home to many of China’s major megacities and industrial hubs, and while they contribute 25% and 30% of the nation’s solar and wind capacity, respectively, they consume nearly half of the nation’s electricity. Though offshore wind represents only about 9% of China’s total wind power capacity, it is gaining traction as these provinces pursue ambitious decarbonization targets. China has already begun tapping into this potential, but further progress will require a strategic and coordinated nationwide approach to fully scale offshore wind as a pillar of coastal decarbonization.

Figure 5

Figure 6

China has established itself as the global leader in offshore wind through rapid and large-scale development. In 2024, China added 4.4 GW of offshore wind capacity, accounting for nearly 55% of all global additions that year. China’s offshore wind capacity grew from less than 5 GW in 2018 to 42.7 GW by March 2025. This represents a sustained compound annual growth rate of 41% over the past five years, two times the global average. Among China’s iconic projects is the 1.7 GW Yangjiang Shaba III complex in the South China Sea, China’s largest deep-sea wind farm. This project alone accounts for nearly 10% of Guangdong Province’s total operational offshore wind capacity.

This growth is enabled by the country’s vast offshore wind potential (estimated at 1,400 GW), its proximity to eastern coastal demand centers, and advances in domestic offshore wind technologies. As of February 2025, China had 67 GW of offshore wind projects in the development pipeline, 41% (28 GW) of which is under construction — a stark comparison to the global average of 2% under construction outside of China.

Figure 7

If China grows its offshore wind capacity, the technology could help displace coal and cut carbon emissions. Guangdong province’s 11.4 GW offshore wind fleet has the potential to avoid roughly 23 million tonnes of CO₂ each year if fully operational — equivalent to burning 8.7 million tonnes of standard coal. Yet offshore wind’s rollout must compete against continued development of gas and coal, which remains prominent in the region, as 13.5 GW of gas power capacity and 23 GW of coal are planned for commissioning by 2027 in Guangdong province alone. Guangdong is not the only coastal province with offshore wind development running in parallel with its fossil fuel capacity. While offshore wind’s capacity to deliver stable electricity makes it particularly well-suited for decarbonizing China’s heavy industries, such as steel and petrochemical manufacturing concentrated along the east coast Bohai Rim, Yangtze River Delta, and Pearl River Delta, it continues to face challenges as coal and gas are still on the rise across China.

China’s coastal provinces collectively outlined a total offshore wind capacity target of 52 GW during the 14th Five-Year Plan period (2021–2025). As of February 2025, China’s operational offshore wind fleet totaled 41 GW — meeting nearly 80% of China’s combined provincial goal. Nearly 10 GW of the 11 GW needed to bridge the gap is expected to become operational by the end of 2025. 

In striving to meet their 14th Five-Year Plan offshore wind targets, each coastal province has pursued its own development pathway. Among them, Jiangsu and Guangdong stand out as national leaders, with 12.6 GW and 11.4 GW of installed offshore wind capacity respectively, accounting for 55% of the country’s total offshore capacity.

Jiangsu was one of the earliest provinces to scale up offshore wind capacity, thanks to favorable shallow-water conditions in the Yellow Sea and early development of intertidal and nearshore zones dedicated to offshore wind development. These conditions made way for the growth of the country’s largest offshore wind supply chain hub, with Yancheng City alone hosting over 47 wind equipment manufacturers. Today, Jiangsu’s newest fleet of offshore wind projects is being pushed into deeper waters as the result of already established offshore wind projects in shallow waters.

Guangdong has emerged as China’s fastest-growing offshore wind market. The province is also home to Mingyang’s OceanX, the world’s largest-capacity floating platform. Unlike Jiangsu’s shallow seabed, Guangdong’s deep waters require jacket foundations or floating structures capable of withstanding frequent typhoons that ultimately raise engineering demands, as turbines need reinforced, storm-resistant designs. China’s floating wind sector has been proactively addressing these challenges, with the development of typhoon-ready designs to face extreme weather conditions. To tame high costs, Guangdong approved large-scale projects (500–800 MW) to capture economies of scale and encourage turbine upscaling, with local original equipment manufacturers like Mingyang rolling out 10–18 MW models to boost energy yield per foundation.

China is rapidly advancing floating wind technology to tap deepwater resources. As of Q1 2025, almost 40 MW is operational across five pilot projects. The first phase (200 MW) of a 1,000 MW Hainan Wanning floating offshore wind farm is scheduled for completion by the end of 2025. China also leads in developing flagship offshore turbines. In June 2024, Goldwind became the first company to commercialize a 16 MW unit at Zhangpu-Liuao Phase 2. Later that year, Dongfang Electric unveiled a 26 MW design with a 310-meter rotor.

China’s coastal provinces are pioneering ways to decarbonize heavy industry and energy systems powered by offshore wind. One major decarbonization pathway is producing green hydrogen from offshore wind. Pilot projects are underway in Fujian, Guangdong, and Shandong, with robust central policy support. Offshore wind is also being utilized for direct electrification of energy‐intensive industries. In Guangdong, for example, a 500 MW offshore wind farm in the South China Sea, slated to connect in late 2025, will deliver 100% renewable power to Germany-based company BASF’s Zhanjiang Verbund chemical complex. In June 2025, Shanghai Lingang announced the world’s first commercial underwater data center powered by offshore wind, sourcing over 90% of its energy from sea-based turbines.

While China remains committed to innovation in offshore wind, the sector faces a key domestic challenge following the phaseout of national subsidies in 2021. At the end of 2021, China phased out its national feed-in tariffs (FiTs), which had guaranteed developers premium rates and supported an Internal Rate of Return (IRR) of roughly 10%. In the rush to meet the subsidy deadline, China installed a record 16.6 GW in 2021, only to see additions drop to about 6.5 GW in 2022. To soften the blow, provinces such as Guangdong, Shandong, and Zhejiang introduced modest local incentives in 2022, including both capacity-based subsidies and tariff-based subsidies.

China’s offshore wind future — Strategic anchors & policy blueprint

China’s offshore wind sector is entering a critical phase of development, requiring a coordinated policy framework that balances industrial scaling, environmental sustainability, and technological advancement. Drawing from international markets, China has the opportunity to refine its approach to offshore wind development and enhance the technology’s long-term competitiveness with fossil fuels. By combining global best practices with domestic policy needs, China can create a stable and coordinated approach to fully scale offshore wind as a pillar of coastal decarbonization.

Adjustments to the project bidding structure could support sustainable sector growth. A hybrid auction mechanism that incorporates both price and technical criteria, such as ecological impact mitigation (e.g., sediment stabilization, noise-reducing foundations), grid integration readiness, and technology advancement (e.g., hydrogen generation, black-start capabilities) can incentivize innovation. Such an approach strengthens the market signals for high-quality projects while reinforcing the long-term resilience and sustainability of the sector. International models like the Netherlands’ zero-subsidy auction system, which prioritizes technological ingenuity through non-price criteria and the United Kingdom’s Contract for Difference (CfD) mechanism, which guarantees long-term price stability by indexing payments to wholesale electricity prices, offer complementary lessons. The Dutch model drives down levelized costs by fostering competition in efficiency gains, and the CfD system mitigates financing risks through 15-year revenue certainty, which can be critical for China’s capital-intensive deepwater projects. China could structure auction criteria to reflect regional priorities, allocating greater emphasis to technical merits in ecologically sensitive zones and prioritizing price competitiveness in mature industrial clusters. This dynamic calibration would reward projects that align with national decarbonization targets while maintaining market-driven efficiency.

Robust spatial planning and ecological safeguards are essential to balancing offshore wind expansion with marine conservation. In December 2024, China announced depth and distance requirements, as well as ecological regulations for new offshore wind projects. Centralized marine spatial planning can play a pivotal role in this transition by identifying suitable development zones based on wind resource availability, ecological sensitivity, and proximity to grid infrastructure. Linking project development to habitat restoration efforts, similar to Germany’s biodiversity compensation models, can align offshore wind expansion with marine conservation goals. This integrated approach helps to ensure that site selection and project development are both environmentally responsible and strategically aligned with national priorities.

Support for industrial-academic collaboration may accelerate technology development, particularly in areas such as typhoon-resilient floating platforms and AI-powered predictive maintenance. Partnerships involving major developers and research institutions, such as state-owned enterprises China Three Gorges Corporation and State Power Investment Corporation, and private wind turbine manufacturer MingYang Smart Energy, have the potential to strengthen innovation ecosystems. These collaborations can help bridge research and commercialization, positioning China at the forefront of offshore wind innovation globally.

About the Solar and Wind Trackers

The Global Solar Power Tracker is a worldwide dataset of utility-scale solar photovoltaic (PV) and solar thermal facilities. It covers all operating solar farm phases with capacities of 1 megawatt (MW) or more and all announced, pre-construction, construction, and shelved projects with capacities greater than 20 MW. The Global Wind Power Tracker is a worldwide dataset of utility-scale, on- and offshore wind facilities. It includes wind farm phases with capacities of 10 megawatts (MW) or more.

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, on Twitter/X @GlobalEnergyMon, and Bluesky @globalenergymon.bsky.social.

Media Contact

Mengqi Zhang

Researcher

mengqi.zhang@globalenergymonitor.org

The post China’s solar and onshore wind capacity reaches new heights, while offshore wind shows promise appeared first on Global Energy Monitor.

Despite controlling vast networks of energy assets deeply embedded in our global economies, private equity firms remain largely unregulated, evading the financial disclosures that would expose the true extent of their impacts.

In a new report, Private Equity, Public Harm, PECR expands on the findings of the 2024 Private Equity Climate Risks Scorecard and Report to examine the impacts of non-greenhouse gas pollutants (non-GHGs) from fossil fuel infrastructure located in the continental United States and backed by private equity investments. 

The non-GHGs included in the analysis are sulfur dioxide (SO₂), nitrogen oxides (NOₓ), volatile organic compounds (VOCs), and fine particulate matter (PM2.5). These pollutants are known to cause or worsen cardiovascular and respiratory conditions such as asthma, lung cancer, heart attacks, and strokes, as well as neurodegenerative diseases like Alzheimer’s and Parkinson’s.¹

The impact of these pollutants across the United States were analyzed using the U.S. Environmental Protection Agency’s (EPA) CO-Benefits Risk Assessment Health Impacts Screening and Mapping Tool (COBRA).² Output data from this model was utilized to examine human health impacts nationwide, at the firm-level, and within two case study regions. In addition to estimating the number of instances of health issues in a given area, the COBRA model also estimates the economic costs of these harms on an annual basis.

Staggeringly, the total health bill from the selected private equity-backed fossil fuel infrastructure in the United States is estimated to range between $11.3–$15.1 billion per year. 

Figure 1

In more concrete terms, the air pollution from these private equity-backed facilities are responsible for ~1,500 emergency room visits and ~1,000 premature deaths every year.³ Moreover, U.S. communities lose over 27,000 work days and over a quarter of a million school days due to health issues caused by this air pollution per year. The latter figure is roughly equivalent to the entire Los Angeles Unified School District—the second largest in the country—being shut down for a day due to poor air quality. Other respiratory issues such as asthma and hay fever (a general allergic reaction to allergens) are also very common as a result of these air pollution emissions.⁴

Figure 2

Behind all of these national impact numbers are the private equity firms in question and the fossil fuel assets in which they are invested.⁵ Health impacts and monetary estimates have been disaggregated to the private equity firm level in this report. Notably, multiple firms cause more than US$1 billion in health impacts per year.

Figure 3

Private equity managers must be transparent about investments in fossil fuels and must also account for the impacts and risks their fossil fuel portfolios have on the environment and local communities. The industry must act to remediate the harms, particularly in communities of color where climate impacts and toxic pollution are the most acute. Private equity managers must simultaneously transition to investing in a clean energy economy that will power our society without these unacceptable health impacts. Given the trillion-plus dollars private equity firms have invested in fossil fuels and the need for immediate environmental action, this report recommends a set of standards based on the climate demands in the private equity scorecard.

Standards:

1. DISCLOSE FOSSIL FUEL EXPOSURE, GHG and NON-GHG EMISSIONS, AND IMPACTS • Disclose all fossil fuel infrastructure and financial estimates and assumptions regarding facility impairment • Disclose all direct and indirect emissions and health-related community impacts. 
2. IMMEDIATELY CEASE INVESTMENTS IN FOSSIL FUEL EXPANSION • Achieve a fossil-free energy portfolio by 2030 • Retire fossil fuel energy facilities by 2030. • Cease gas flaring and venting by 2025.
3. REPORT A PORTFOLIO-WIDE ENERGY TRANSITION PLAN • Disclose a portfolio-wide transition plan • Disclose role of voluntary carbon offsets immediately and cease their utilization by 2025 • Disclose use of carbon removal, carbon utilization and storage, and related technologies.
4. INTEGRATE ENVIRONMENTAL JUSTICE • Establish robust due diligence, verification, and grievance redress mechanisms to ensure that human health, human rights, and land rights are respected • Require all portfolio companies to adopt no deforestation, no peat, and no exploitation (NDPE) policies • Develop a just transition program with impacted communities and workers. 
5. PROVIDE TRANSPARENCY ON POLITICAL SPENDING AND ENERGY LOBBYING • Disclose political spending and climate lobbying at asset manager, portfolio company, and trade association level • Provide transparency on alignment with global standards on responsible corporate climate lobbying.

About the Private Equity Climate Risks (PECR) project

This study is part of the Private Equity Climate Risks (PECR) project, a multi-organization initiative investigating private equity’s role in the climate crisis. Through its Private Equity Tracker, Global Energy Monitor collaborates with the Private Equity Stakeholder Project (PESP) and Americans for Financial Reform Education Fund (AFREF) to document the environmental and social toll of private equity-backed energy assets — and the gap between these firms’ ESG claims and their actual investment practices.

Media Contact

Alex Hurley, Project Manager Private Equity Tracker

Global Energy Monitor

alex.hurley@globalenergymonitor.org

The post Private Equity, Public Harm appeared first on Global Energy Monitor.

Coal was once billed as the “buried sunshine” of a prehistoric past. But the world has now entered an age of solar energy — a time when harnessing the sun has become more accessible, affordable, and environmentally sustainable than digging it up in fossil fuels. In 2024, the world installed a record-breaking 599 gigawatts (GW) of solar capacity, and currently has more than 2,000 GW of utility-scale solar projects in development. But that requires widespread land use, and today’s developers often struggle to secure prime locations that aren’t already in use, or off limits.

What looks ideal on a solar map can prove impractical on the ground. But vast tracts of scarred landscapes already sit idle in much of the world waiting for a second act — abandoned coal mines.

Global Energy Monitor (GEM) conducted a worldwide survey of surface coal mines closed in the last five years (since 2020) and those forecasted to close over the next five (by the end of 2030). The first-time analysis shows that over 300 surface coal mines recently out of commission could house around 103 GW of photovoltaic (PV) solar capacity, and upcoming closures of large operations could host an additional 185 GW of solar across 127 sites (see Methodology). These abandoned coal mines are predisposed to renewables siting with grid-adjacent and even pre-cleared acreage. 

If these potential solar projects came to fruition, the world could build almost 300 GW of solar capacity on mined out lands by the end of 2030. Uptake on that scale is equal to 15% of the solar that has already been built globally and would add enough solar capacity to inch the world one step closer to tripling renewables before the end of the decade.

Some of these projects are already underway. GEM’s new data on coal-to-solar projects show that China has 90 operational coal mine-to-solar conversions, with a capacity of 14 GW, and 46 more projects, with 9 GW, in planning.

The coal-to-solar transition offers a rare chance to repair the environmental hazards and eyesores of open pits and generate an estimated 259,700 permanent jobs in the solar industry — five times more than the current coal mining workforce of the United States. During construction, these projects would also create even more temporary construction jobs (317,500), which together is more than the number of workers that the coal industry is expected to shed globally by 2035. Constructing solar on upheaved lands isn’t just land reclamation — it’s a chance to align land restoration, clean energy goals, and local job creation.

And that’s just the beginning of possibility. While recent closures are the likeliest candidates for new development, plenty of other closed mines may still be in suitable condition. The world has closed over 6,000 coal mines since 2010, most of them in China during the coal industry’s restructuring and in the U.S. where economic headwinds forced operators to slash their 1 billion tonne industry in half. The earlier closures happened, the harder it is for developers to trace ownership tenures and infrastructural changes that could impede future repurposing, though it is still possible to scrutinize project viability on a site-by-site basis.

Key findings

• A nation’s worth of solar potential: Developers could build almost 300 GW of photovoltaic solar capacity on open pit coal mines that closed over the past five years (since 2020) and those expected to close over the next five (by the end of 2030) — roughly what it takes to meet the annual electricity consumption needs of a country like Germany, and the projects currently operational or in development represent only a small fraction of this vast potential
• Grid-ready sites: Nearly all abandoned coal mines and upcoming closures are in close proximity to existing grid infrastructure, including substations and transmission lines — 96% of recently abandoned mines are less than 10 km from the grid, and 91% are within 10 km of a grid connection point, such as a substation.
• Job dividends: 259,700 permanent jobs could be created at coal-to-solar transition sites in manufacturing, wholesale trade and distribution, and professional services, and an additional 317,500 temporary and construction jobs, which is together more than the number of workers that the coal industry is expected to shed globally by 2035.
• China’s buildout: China has the most projects underway, with 90 operational coal mine-to-solar conversions, a capacity of 14 GW, and 46 more projects in planning, a capacity of 9 GW.
• Transitions that matter: The coal-to-solar transition is primed in both advanced and developing coal economies, including Australia, Indonesia, the United States, and India.

Figure 1

Coal’s dirty footprint

The coal industry remains a stubborn fixture in the global energy mix, even as it experiences a bust in its historic markets. With the industry’s decline has come a rash of mine closures in recent years — more than 700 underground and surface operations shuttered since 2020. With phaseouts in motion, government climate goals, and economic unviability, coal mine closures will keep mounting in the years ahead. 

Today, 3,800 coal mines produce 95% of the world’s coal. With national commitments to phase out coal in 33 countries, the industry will leave behind hundreds of abandoned mines and eventually thousands once mega producers China and India chip away at the industry.

But when coal mines shutter, they leave behind large swaths of degraded and abandoned lands. The coal industry is land hungry in terms of the sheer acreage required to produce a megawatt of energy. Some surface mines are large enough to span an entire metropolitan area.

Figure 2  Source

While no agency publishes figures on the number of square kilometers (km²) eaten by coal mining, one team of academics at Vienna University used satellite imagery and machine learning to reported that the world has over 101,583 km² of mined out land and processing sites related to coal, copper, and gold, including open cuts, tailing dams, waste rock, waste ponds, and processing sites. These sites include long abandoned operations and sites ill-suited for repurposing. But coal contributed over half (52.5%) of all mineral fuels extracted in 2023, producing over 8 billion tonnes. The open pit mines alone are only part of the problem: The coal mine industry also disturbs the vicinity around mines for processing, transportation, sludge storage, and power.

After mining, cleanup or reclamation initiatives help restore these vast acreages to prior conditions. But the practice of reclamation and cleaning up the mess after mining is not a standard routine in much of the world. The United States passed federal reclamation laws in the 1970s, but those policies have lost their teeth over time, and today over 4,000 km² remain gouged out and unreclaimed. Under some state and national laws, mining companies are required to set aside funds to safely decommission sites once operations end. But as a global practice, this cleanup rarely happens. Without a profit motive to remediate, and weak government enforcement, many companies simply walk away — leaving behind unstable land and unmet obligations. As such, old mining sites have become prone to hazards and accidents, including in Indonesia, one of the largest coal producers, due to lack of enforcement for rehabilitation obligations.

Opportunity where coal once stood 

Where coal once characterized local histories, solar now offers a chance to power the future. The utility-scale solar industry, the fastest growing energy technology in history, requires a large amount of real estate for PV farms. One of the oldest criticisms of solar is the land use requirements for ground-mounted installations. While many of those criticisms have proven overblown, there are nonetheless many legitimate examples of unjust and environmentally harmful land usage from deploying utility-scale solar infrastructure. The residents of Bianjiaqu, Shanxi in China, for instance, have alleged that a solar developer ignored citizen concerns during negotiations, damaged collectively-owned fertile land, and provided insufficient compensation. As solar developers provoke backlash in some corners of civil society, repurposing already-disturbed land, such as former coal mines, can help reduce or avoid conflict over land use.

GEM’s Global Coal Mine Tracker, a comprehensive dataset of coal mines, has identified 311 surface coal mines that have been idled and degraded since 2020. These abandoned mines sprawl over 2,089 km², an area nearly the size of Luxembourg. With repurposing, these coal-to-solar projects could site 103 GW of solar power capacity on derelict lands.

GEM’s analysts further identified 3,731 km² that may be abandoned by operators before the end of 2030, owing to reserve depletion and the reported life of the mine. If these operations close, they could site 185 GW of solar power capacity. 

Over the course of the 2020s, some 446 coal mines and 5,820 km² of abandoned mine lands, in total, could be suitable for solar repurposing. With development, these projects could harbor nearly 300 GW of PV solar potential, equivalent to 15% of the globally installed solar capacity.

Figure 3

Figure 4

When coal mines are repurposed for solar, the results can range from small community arrays to large utility-scale projects. The size of the buildout influences the cost, complexity, and political landscape. Smaller projects (1–5 MW) can be quick wins, plugging into local distribution lines to power schools and neighborhoods, often with strong local support. They carry higher costs per megawatt and usually need creative financing such as bundling multiple sites into a single portfolio. But small projects have a considerably better chance of progressing in areas where big projects will never break ground. The mid-sized solar projects (5–50 MW) mix ambition with feasibility — big enough to attract corporate buyers and competitive investment but still small enough to tap into existing grid infrastructure without major upgrades. Mega projects over 100 MW often require transmission buildout, vast land preparation, and serious patience. But for coal communities looking to make an energy transition once and for all, these large utility-scale projects can radically transform communities into clean energy hubs.

The coal mines identified for repurposing between 2020 and 2030 offer a wide range of solar opportunities. About one-third of the 438 coal mine sites are suitable for community-scale solar projects, whereas the majority are capable of supporting larger, utility-scale solar developments. Nearly 70% possess land areas suitable for solar projects exceeding 50 MW and more than 200 coal mine sites are estimated to have a solar potential greater than 100 MW. Around 10% of the total potential coal mines are projected to have a solar capacity exceeding 1,000 MW. Coal mines with an estimated solar potential under 5 MW represent just 8% of the total, while those between 5 MW and 50 MW comprise about a quarter of the opportunities (24%).

In most cases, abandoned coal mines are adjacent to grid infrastructure, including transmission lines and substations. For recently closed mines, 96% are within 10 km of the grid and 91% are within 10 km of a grid connection, such as a substation. For operating mines expected to close before the end of 2030, 87% are within 10 km of the grid and 76% are within 10 km of a grid connection. These mines are so close to the grid that renewable developers have even investigated the locations for large-scale battery storage. Some sites have also been explored for green hydrogen production. The proximity to the grid can make these coal-to-solar projects more cost-competitive.

But converting steady, baseload coal power to variable solar power typically requires targeted upgrades in grid infrastructure. Solar power requires battery storage, grid-forming inverters, or synchronous condensers to maintain frequency and voltage support. As a result, technological upgrades are often needed to a grid built for fossil fuels, so that it can handle the fluctuations in solar generation. And even with infrastructure in place, many projects must complete new interconnection studies and permitting processes to ensure the system can reliably accept renewable power.

Figure 5

Where the ground is ready

The coal industry leaves behind an enormous area of untapped potential once production ends. During the height of the global Covid pandemic, in 2021, nearly 1,164 km² was abandoned, corresponding to an unrealized solar potential of 58 GW. But a second peak is projected in 2030, when over 700 km² of mine lands are expected to close based on mine-level forecasts, equivalent to an estimated solar potential of 36 GW.

Figure 6

Coal’s footprint has sunk deepest in the very places where clean energy remains an urgent need. The world’s largest coal producers — Australia, Indonesia, the United States, and India — hold some of the greatest potential for solar redevelopment on mine lands. But a total of 28 countries with recently abandoned surface coal mines are suitable for repurposing, representing a total potential solar capacity of 288 GW. 

The opportunity to align reclamation with renewable energy buildout is evident in high-income countries and middle-income nations. In South Africa, for example, 20 identified coal mine sites could support nearly 13 GW of solar, twice as much as the country’s currently installed capacity, offering a way to accelerate the country’s clean energy goals while repurposing lands scarred by extraction. The sprawling German lignite mines could host over 4 GW of solar, which is a small share of the country’s total solar capacity, but a significant stride for a coal-dependent region.

In Australia alone, more than 1,470 km² of mine sites could support over 73 GW of solar capacity, roughly double the country’s entire current solar fleet. Indonesia’s coal mines offer space for nearly 60 GW of potential solar, 100 times more than the currently installed capacity, while the United States stands out not just for its capacity (49 GW) but for the sheer number of identified sites — 217 in total. In India, over 500 km² of mine lands could host more than 27 GW of solar, about 37% of currently installed capacity, offering a critical opportunity to advance clean energy targets while supporting reclamation in coal-heavy regions like Jharkhand and Chhattisgarh.

Figure 7

The establishment of clear regulatory frameworks for rehabilitating former coal mining sites is crucial to ensure an equitable transition. This is especially urgent in countries such as the United States, Canada, Russia, Germany, Serbia, Poland, the Czech Republic, the United Kingdom, and Slovenia, which have a large number of abandoned mines. In the United States, Texas, Kentucky, and West Virginia have already initiated several coal mine conversion projects, led by both governmental initiatives and private stakeholders (see Coal-to-solar in action).

Figure 8

But rehabilitation policy remains necessary in coal-heavy regions with forthcoming closures. Queensland and New South Wales in Australia, as well as East and South Kalimantan in Indonesia, are likely to have substantial land areas released from coal mining activities within the next five years, much of it suitable for solar development. Several of these regions have already initiated pioneering projects or implemented policies for repurposing these mines to solar energy at the subnational level (see Coal-to-solar in action).

Figure 9

Since sun exposure is clearly a prerequisite for successful solar installations, one key advantage of former surface mines is that they are largely cleared of tall vegetation and often sit on open plateaus.

But the installation of solar power capacity is only one measure of progress. Building solar on former coal mines creates jobs, makes abandoned lands safer, and tackles coal sector methane leaks that might otherwise linger for decades.

The work of the transition

The path to a just energy transition runs through the heart of coal country — 2.7 million coal miners are directly employed at the world’s operating coal mines. But these workers face the harsh prospect of job layoffs due to scheduled mine closures and a market shift toward cheaper wind and solar power generation, whether or not their home country has a coal phaseout policy in place. GEM’s previous research has found that the coal industry is expected to shed nearly half a million jobs in the mining sector by 2035, affecting on average 100 workers per day. The coal industry itself shoulders responsibility for the sector’s unpredictable future, yet GEM noted that most mines expected to close in the coming decades have no planning underway to extend the life of those operations or to manage a transition into a post-coal economy. In the United States, the coal mining sector employs fewer than 50,000 workers.

The clean up of degraded lands creates jobs in mining communities. Reclamation calls for the same brute machinery as mining, except workers undo the damage. Crews reset topsoil at old mine sites to cut down on contamination, bring back wildlife, and sometimes take on bigger civil works or community-building efforts.

Once cleanup is finished and solar installation begins, 1 MW of installed utility-scale solar, on average, creates 2.1 jobs, including permanent and temporary construction employment in advanced economies. The operations and maintenance at solar farms, including panel cleaning, inverter maintenance, and vegetation management, may require additional work, depending on site conditions, including inspecting water treatment systems or ground settling. 

The boom in solar jobs continues to lead the energy sector, with about 500,000 new solar jobs created globally in 2023. In the short term, a rapid buildout of solar on existing and anticipated mine closures could provide 259,700 permanent jobs, and 317,500 temporary and construction jobs globally. While the number of permanent jobs is not nearly enough to offset mining job losses, especially in China and India, they can provide a “lifeline” to communities sorely in need of a just transition.

Addressing physical and emissions hazards

Turning old coal mines into solar farms goes beyond clean power or paychecks — it’s also a way to heal the land and address the emissions that coal left behind.

Bringing a coal mine back from ruin is no easy task. As with many derelict landscapes, clearing debris, scrap materials, or remnants of past industrial activity is required before work can safely begin. With deep surface mines, slopes are often unstable and prone to erosion and collapse. Pits can fill with toxic runoff and coal ash, and other industrial wastes can leach into nearby waterways. The mine’s safety infrastructure in fencing, signage, and drainage can break or go missing with neglect. These sites become hazardous to the environment and to local communities left to live in the wreckage. The improper care of abandoned mines has led to dangerous conditions, including sinkholes under neighborhoods and parks in Pennsylvania, the evacuation of entire towns and villages in Shanxi, China, deadly roof cave-ins at mines illegally operated after closure in India, and ongoing water and agricultural pollution in South Africa.

Reclamation helps make the land safer for solar industry workers and surrounding communities. These restoration processes can stabilize unsettled ground, mitigate hazardous zones, and restore healthier soil layers. Adding solar infrastructure on top reinforces that process, keeping the land in productive use while reducing the risk of erosion and runoff pollution. Instead of abandoned scars on the landscape, these sites become managed, monitored spaces — cutting down on environmental hazards and offering a safer footprint for the communities around them. Within China, subsidence areas of some former coal mines, particularly in Shanxi and Inner Mongolia, have already been converted into large-scale solar farms under government-led pilot projects. These transitions are especially crucial as abandoned mines become more common with the rundown in the coal market and phaseout of coal.

Beyond the local environment, coal-to-solar projects can help tackle an imminent climate threat — methane emissions from abandoned seams. When a coal mine is closed, methane emissions from exposed coal seams and fractured rock can continue to leak for years unless operators take proactive mitigation measures. Slashing methane is one of the fastest, most effective ways to slow global warming in the short term. But one GEM analysis found that recently abandoned underground mines in the EU collectively emit nearly 200,000 tonnes of methane per year, equal to the emissions from the Nord Stream gas pipeline leak. The actual emission levels remain largely unchecked and unreported in many countries due to legal ambiguities over accountability for abandoned sites, incomplete information about the profiles of abandoned mines, and the absence of a comprehensive Monitoring, Reporting, and Verification (MRV) framework.

The methane emissions at abandoned surface operations are even more difficult to measure because they are diffuse with low concentrations. Yet proper reclamation procedures could reduce these long-term leaks. Installing a solar farm typically requires covering the site with soil, gravel, or other materials to stabilize the ground and prevent subsidence. This process acts as a physical barrier, reducing oxygen infiltration and sealing methane pathways, which slows or blocks the release of gas into the atmosphere.

What stands in the way

While the technical potential is high, the actual buildable area depends on legal and ecological factors. When mining happens in forested areas or sensitive ecosystems, for instance, legal requirements could require the developers or state to return the land to something close to its original condition. Building solar might not initially qualify, but if a solar project is seen as a public benefit or part of a clean energy strategy, then post-mining land use plans could be updated and amended to reflect those needs.

One common hurdle to building solar projects on former coal mines is identifying land owners. When coal operations close, companies often unload properties to junior firms or file for bankruptcy. The change in ownership makes it difficult to track control of land titles over time. If a coal company reclaims the land after mining, then solar development must still wait until the coal firm releases its bond and the rights return to whoever held it first, which may be another mining company, a landholding firm, or a longtime community landowner. That said, mine lands are frequently owned by a single entity, which means once the contiguous owner leases or sells, a project can proceed relatively quickly compared to greenfield development projects, which require acquiring large tracts of land under fractured property regimes and multiple owners.

But it is essential for states and developers to establish a transparent and equitable land rights return process. In India, the country with the fourth-largest potential for coal mine-to-solar transitions, many closed coal mines have remained idle for years due to the absence of clear policies governing closure and the return of land rights. In many instances, these abandoned mines, often not officially closed, are directly transferred to renewable energy or afforestation projects, bypassing the return of land to local communities. Addressing this issue is critical to prevent the replication of unjust land ownership regimes in the renewable energy sector. 

GEM’s Global Coal Mine Tracker provides data on the last known coal owner and parent company at abandoned coal mines. The transfer of coal properties is one reason this analysis focuses on recent closures, rather than all abandoned mines over decades — there is less time for property transfers and easier paths to pinpoint the ownership chain.

Figure 10

Coal mines have complicated ownership structures, with a mix of corporate, government, and financial entities. But parent companies in the sector remain highly concentrated. Just ten owners are responsible for over half (57%) of the land area abandoned by coal mining since 2020.

Within some jurisdictions, permitting coal-to-solar projects may prove burdensome, since developers may need to simultaneously deal with mining authorities, environmental regulators, local zoning boards, and electric grid regulators. This patchwork can lead to a lengthy timeline to secure all permits and increase front-end legal and consulting costs. There might be uncertainty within some agencies about classifying a solar farm as an acceptable “post-mining land use,” for instance, which could require changes to the reclamation plan or special exceptions. On the other hand, in Germany’s lignite mining regions, government authorities have already simplified the process, recognizing the urgency of the energy transition. 

But the biggest obstacle remains the associated capital costs with coal-to-solar transitions. Developing solar farms on abandoned surface mines typically costs more per megawatt than building on greenfield sites, largely due to the complex conditions left by mining activity. While the weighted cost for utility-scale solar, including on greenfield sites, runs near US$1.5 million per MW,  projects on former mine lands often exceed these figures because of remediation needs such as fixing soil instability, uneven terrain, and infrastructure gaps.

Thanks to plummeting solar module prices and improvements in efficiency, utility-scale solar now has one of the lowest Levelized Cost of Energy (LCOE) of any generation source. The LCOE is a common metric that spreads a project’s total costs over its lifetime energy output, providing a dollar per megawatt hour ($/MWh) value. While building a solar farm on a coal mine could require a slightly higher LCOE compared to an ideal greenfield project, public subsidies and incentives (like tax credits in the U.S.) can create economics that outperform greenfield projects. If grid interconnection is efficient, for instance, and the land is cheap, those factors can neutralize the cost differential.

But creative financing may be needed to get these projects off the ground, including public incentives, green banks, or community investment. Given the “known unknowns” of former mining lands, some traditional financing mechanisms may prove more difficult to secure or come with higher interest rates and insurance costs. Some small-scale solar projects (1–20 MW) might not even attract large investors, since transaction costs are similar to large projects but with lower rates of return. 

Despite the potential premium, solar development on mine lands remains a compelling strategy. These projects provide the potential to link reclamation with economic renewal in coal-affected regions. Redeveloping such sites supports local livelihoods and helps mitigate social and environmental harms. With appropriate siting on former strip mines, the development process can become more stable and efficient, helping to attract interest from solar developers.

Solar can take coal’s place, if challenges are addressed

Despite real challenges to coal repurposing, there are plenty of reclamation success stories. The work is underway among many of the world’s major global solar developers and state and national governments that have pursued coal-to-solar co-location projects. GEM has compiled preliminary data on at least 100 active coal-to-renewable transition projects globally (including 41 former coal mine sites), with additional projects being announced each month. Thirty-seven of these initiatives involve converting coal mines into solar energy facilities. GEM also maintains a more comprehensive dataset on China’s coal mine-to-solar transitions, as project names often reference their fossil fuel origins.

Figure 11

Back in 2021, the German power company RWE and Greece’s state-owned PPC launched Meton Energy, a joint-venture dedicated to installing 2,000 MW of solar electricity on Greece’s lignite fields. As of April 2025, nine projects totaling 940 megawatts peak in direct current (MWp/dc) have been sited on the footprint of the Amynteo opencast mine in Western Macedonia. Five projects have been completed and are generating power, with four more expected to be operational by the end of 2025. An additional 567 MW of solar will be commissioned in 2027 in Central Macedonia. These mine areas are within a short distance of existing transmission infrastructure, allowing for speedier deployment and evacuation of solar resources to populations throughout Greece.

China, the world’s largest producer and consumer of coal, is also making large investments in coal-to-solar transitions. Shanxi, the coal-producing region located on the Loess Plateau with abundant solar resources and vast areas of land, has a robust pipeline of solar projects that are to be built on mine subsidence land. In 2024, the provincial government announced that three projects totaling 5,000 MW will be installed in the city of Datong’s subsidence zones. The projects will be online in 2026 and 2027. These projects are in addition to the existing 1,000 MW of solar operating on approximately 200 km² of former coal mine land. Meanwhile, wind, solar, and storage projects totaling 6,000 MW will be delivered to customers in Beijing, Tianjin, and Hebei provinces via the Datong-Tianjin ultra-high voltage power line, and Yangquan City has installed 950 MW of solar across 4,570 km² of subsidence land. 

Inner Mongolia’s 14th Five-Year Plan on Renewable Energy established a target of 5,000 MW of solar installed on former coalfields in Erdos, Tongliao, Wuhai, Alxa, Bayannur, Baotou, and other areas with stable geological conditions and acceptable access conditions. Inner Mongolia is already home to China’s largest operating mine-to-solar project, the 3 GW Inner Mongolia-Shandong Power Export Ordos Mined-Out Area (China Energy Investment) solar farm.

Figure 12

Solar is only the beginning 

While solar panels often lead redevelopment on old mine lands, many projects are stacking uses, combining power generation with storage, grazing, and ecological repair. Renewable energy developers in Australia, for instance, have begun to reimagine underground mining operations. The New England Renewable Energy Zone (REZ), in New South Wales, for instance, has garnered interest from investors due to its potential for pumped hydropower storage and its existing transmission lines connected to population centers in Upper Hunter, Queensland, and New South Wales’ eastern coast. This storage complements the generation capacity planned in the South West Renewable Energy Zone , which is located in southern NSW and is ripe for wind and solar development. With an initial target of 2,500 MW of wind and solar capacity in the South West REZ, expressions of interest from developers included proposals for 34,000 MW in generation and storage projects. These projects will leverage existing and in-development transmission capacity to evacuate power. Together, both REZs are expected to create an estimated 10,000 jobs across construction and operations and spur over US$17 billion in private investments.

These projects have turned remnants of the fossil era into storage tools for the energy transition. Some sites have been converted for pumped hydropower or compressed air energy storage, using mine shafts and voids to hold and release power on demand. India’s Ministry of Coal, for instance, is assessing over 20 abandoned mines for potential pumped storage development, consulting with stakeholders about business models. Likewise, in Australia, a collaboration with Glencore to establish energy storage infrastructure in Queensland, capable of storing 2 GWh of energy, would be sufficient to power around 120,000 households. The industry has also tapped geothermal heat from flooded tunnels for low-carbon heating and cooling. In the UK, the government is exploring geothermal potential in over 100 flooded coal mines, utilizing naturally heated water for heat pumps, with successful applications at the Gateshead Mine. One US$2 million study is assessing the feasibility of using geothermal heat from mine water to provide heating for over 100,000 homes in the West of England. There are reportedly early stage projects exploring gravity-based storage, underground hydrogen reserves, and battery installations within mine spaces. In some cases, mines have been considered infrastructure for energy-efficient data centers or for carbon sequestration. Together, these efforts show how the infrastructure of extraction can be reworked to serve the next generation of energy systems.

Just as underground mines are being reimagined for storage and clean energy, former surface mines also offer potential far beyond solar panels. In areas with suitable geology, surface mines may also be candidates for pumped hydro storage, using reshaped pits as reservoirs. Others are being considered for agrivoltaics, combining solar development with grazing or crop production, or as sites for native habitat restoration alongside energy generation. China has built the world’s largest sites of floatovoltaics, where floating PV is built on a collapsed coal mine that was filled with water — a 70 MW array covering 63 hectares of a former pit lake​.

One of the most successful examples of agriculture on reclaimed mine lands comes from replanting native grasses, wildflowers, and pollinator meadows, bringing life back to mined landscapes. In the U.S., the Appalachian Botanical Company has been cultivating lavender on approximately 50 acres of reclaimed coal mine land in Boone County, West Virginia. Lavender, well-suited to dry, rocky soils, flourishes on this reclaimed ground. The company also keeps bees on site, producing honey while boosting pollinator habitats. Meanwhile, in the U.K., projects like the Dearne Valley Green Heart and the National Coal Mining Museum have turned former colliery grounds into thriving meadows. Together, these efforts help revive the land and create jobs for local residents, including those facing employment barriers.

Conclusion: The promise of renewal

The legacy of coal is written into the land — open pits, buried seams, and abandoned sites that still shape local economies and environments. But that legacy does not have to define the future. Whether in Queensland’s sprawling fly-in-fly-out open pits to the rolling spoil piles of Kalimantan, these sites hold more than the memory of extraction; they hold space for renewal. Repurposing mine lands for solar development offers a rare chance to bring together land restoration, local job creation, and clean energy deployment in a single strategy.

The coal-to-solar opportunity is not theoretical. The world’s largest coal-producing regions hold the greatest potential for solar development on disturbed lands, in those places where grid connections often already exist, where skilled labor forces stand ready, and where reclamation is urgently needed. But realizing this potential will take deliberate action. The transformation will require policy frameworks that prioritize renewable development on mine lands, investment strategies that recognize the value of linking reclamation with clean energy, and community engagement that puts local jobs and local voices at the center of the work. But with the right choices, the same ground that powered the industrial age can help power the climate solutions we now urgently need.

About the Global Coal Mine Tracker

The Global Coal Mine Tracker is a worldwide dataset of coal mines and proposed projects. The tracker provides asset-level details on ownership structure, development stage and status, coal type, capacity, production, workforce size, reserves and resources, methane emissions, geolocation, and over 30 other categories. 

The most recent release of this data in May 2025 includes operating mines producing 1 million tonnes per annum (mtpa) or more, with smaller mines included at discretion. The tracker also includes proposed coal mines and mine expansions with various designed capacities.

About the Global Solar Power Tracker

The Global Solar Power Tracker is a worldwide dataset of utility-scale solar photovoltaic (PV) and solar thermal facilities. It covers all operating solar farm phases with capacities of 1 megawatt (MW) or more and all announced, pre-construction, construction, and shelved projects with capacities greater than 20 MW.

The most recent release of this data was in February 2025.

Media Contact

Ryan Driskell Tate

Associate Director

ryan.driskell.tate@globalenergymonitor.org

The post Bright side of the mine appeared first on Global Energy Monitor.

Despite mounting global climate commitments, including a consensus at COP28 to transition away from fossil fuels, the world’s oil and gas producers are developing 63 new oil and gas fields before 2030, according to the latest data from Global Energy Monitor. While public attention and policy is often focused on mitigating CO2 emissions from burning fossil fuels, reducing methane pollution from producing oil and gas is arguably just as urgent. Methane is an extremely potent though short-lived greenhouse gas — how it is managed today could either buy crucial time for or irreversibly undermine long-term climate goals.

Together, the 63 fields in development could emit 2,300 kilotonnes (kt) of methane annually from their production activities before 2030, enough to rival all of Europe’s current fossil fuel production emissions. While the European Union’s new methane regulations will require all oil and gas importers to abide by new intensity standards, there is no room left in the global carbon budget to swap improvements in methane abatement for increases in oil and gas production. Additionally, these fields are coming online at a time when global demand for oil and gas is expected to peak. Therefore, this new wave of production threatens to unnecessarily entrench emissions and undercut progress on climate mitigation.

GEM’s latest findings build on its April 2024 analysis, the first to estimate potential methane emissions from proposed oil and gas projects using publicly available information. Without equipment-level inventories for in-development projects, which are typically non-existent or proprietary, GEM’s methodology offers reliable proxies for assessing the scale of the methane threat posed by new oil and gas assets. 

Key points

• Sixty-three oil and gas fields in development slated to reach their production design capacity before 2030 could emit 2,300 kt of methane annually. This is equivalent to all methane emissions from current fossil fuel production in Europe. 
• Several potentially high-emitting fields, including Marjan Expansion, Bahr Es Salam, Yellowtail, and Uaru, are slated to reach their production design capacity before they will be subject to the monitoring, repair, and verification standards outlined in the European Union regulations.
• There is no room in the global carbon budget for “trading” enhanced methane mitigation for increased oil and gas production — both are necessary in order to slow climate change.
• Despite falling global demand for fossil fuels, the oil and gas industry continues to pursue new fields year on year. Roughly 13% of potential emissions come from projects newly in development. 
• There are major gaps in data transparency: None of the top three operators with fields in development (Saudi Aramco, Gazprom, and ExxonMobil) have submitted data yet to the United Nations Oil and Gas Methane Program 2.0 (OGMP 2.0), while two of these (Saudi Aramco and Gazprom) have no public intention to do so.

Potential methane emissions are concentrated in a handful of fields

Just ten oil and gas fields, located in Guyana, Libya, Russia, Saudi Arabia, United Arab Emirates, and Uganda, account for over half (1,196 kt) of all potential methane emissions identified in this analysis. ExxonMobil’s Whiptail field, a Guayanese project discovered in 2021, reached its final investment decision in 2024. Whiptail, along with the Uaru and Yellowtail fields, make up the Stabroek block which is Exxon’s largest buildout outside the Permian basin and has transformed Guyana into a major producer. Additionally, the Kharasaveyskoye field, located in Russia’s arctic Yamal peninsula, is now projected to reach its production design capacity in 2026. This project is also associated with a pipeline in development, the Power of Siberia 2, which is expected to transport gas originally destined for the EU market prior to the invasion of Ukraine. Similarly, the Tilenga field, which has attracted controversy due to its potential biodiversity impacts, is now reported to reach its production design capacity in 2026 as well.

Several of these major fields, including the Marjan Expansion, Bahr Es Salam, Yellowtail, and Uaru are located in countries that export oil and gas to the European Union. However, they are slated to reach their production design capacities before 2027, the year that exporting fields must meet the same monitoring, reporting, and repair standards as EU fields. The potent and fast-acting methane emissions from these fields will contribute to climate change for several years without significant international oversight during a critical period before the regulations come fully online.

Figure 1

In the meantime, there is still considerable progress to be made with respect to methane monitoring and management. Accurate measurement-based, asset-scale data remain elusive — the United Nations’ Oil and Gas Methane Program 2.0 (OGMP 2.0), which seeks to become the gold-standard for monitoring, reporting, and verification, published data covering 28% of global oil and gas production but only accounted for 1.8% of total upstream methane emissions, even after marked improvements in participating companies’ activities over the past two years of the program. While new satellite methodologies enable operators to quickly find and make repairs, satellites cannot capture imagery everywhere at once, and some regions are far more challenging to monitor than others. Additionally, of the methane plumes reported to operators and governments by the UN’s Methane Alert and Response System, fewer than 2% of notifications garnered a response the UN classified as “substantive” toward addressing the emissions. 

Top operators of new methane sources withhold crucial data

Many of the new fields in development are operated by companies that have historically refused to publicly share information regarding their emissions in line with international standards. None of the top three operators with fields in development have submitted data to the OGMP 2.0, and two of these (Saudi Aramco and Gazprom) have no stated public intention to do so.

Emissions from the potential fields that operators have submitted to the OGMP 2.0 generally exceed reported company-wide emissions. This discrepancy could be due to a number of factors, including underreporting of assets to the OGMP 2.0 and companies not yet reaching the OGMP 2.0’s highest levels of monitoring and reporting. For comparison, the emissions factors used in this analysis skew conservative: 0.82 kg per barrel of oil equivalent (BOE) in comparison to the Oil Climate Index plus Gas (OCI+) average across the dataset of 0.96 kg/BOE.

Additionally, OGMP 2.0 members are only required to set either intensity or absolute methane emissions reductions targets. Even companies meeting ambitious intensity-based targets could still increase their net methane emissions through new extraction operations like the ones highlighted in this report. In summary, international efforts to monitor, report, and verify methane emissions leave room for operators to emit troubling amounts of methane into the atmosphere.

New fields could undermine international commitments to the Global Methane Pledge

The majority of the top twenty countries in terms of potential emissions, with the exception of Russia, Uganda, Iran, and Algeria, are signatories of the Global Methane Pledge (GMP), a voluntary commitment to slash methane emissions by 30% by 2030. As in the previous year, the potential emissions from signatory countries are meaningful in comparison to these countries’ current methane emissions: Saudi Arabia (15% of countrywide emissions which were 2,863 kt in 2024), Guyana (150% of countrywide emissions, which were 165 kt in 2024) according to the International Energy Agency’s (IEA) Methane Tracker.  To meet their GMP commitments, these countries must greatly enhance their abatement protocols and reduce emissions from other sectors.

While the increase in potential methane emissions from United States fields (0.38%) is small in comparison to the country’s overall methane emissions (35,297 kt in 2024), it is large in absolute terms, greater than any other GMP signatory besides Saudi Arabia and Guyana. The United States is seeking to expand liquid natural gas (LNG) exports to the EU amidst declining Russian imports. However, policy changes under the Trump administration could complicate U.S. exporters’ compliance with EU methane regulations. Such changes include cutting the budgets of federal agencies involved in disseminating technical assistance for methane mitigation worldwide, signaling support for eliminating key incentives for oil and gas methane management, and using “methane” as a keyword for screening grant programs for elimination. In summary, regulatory and political uncertainty around U.S. oil and gas development raise the stakes for mitigation and phaseout efforts globally.

Figure 2

Figure 3

Oil and gas companies continue to invest in new methane-emitting infrastructure each year

GEM’s 2025 Global Oil and Gas Extraction Tracker update confirms a troubling trend: Oil and gas companies are continuing to make investments in methane-emitting infrastructure. Despite global commitments to reduce methane, 13% of potential emissions identified in this year’s analysis come from new fields in development, demonstrating that the industry continues to pursue new projects year after year.

Between March 2024 and February 2025, 304 kt of potential methane emissions were associated with projects that changed status from “in development” to “operating.” Only 139 kt of potential emissions were associated with projects that were cancelled in the same intervening year. Approximately 283 kt of the emissions analyzed in this briefing were either new to GEM’s Global Oil and Gas Extraction Tracker or were previously shut-in or only discovered as of 2024 and are now in development. Additionally, 354 kt were excluded from this year’s updated analysis due to stricter inclusion criteria.

Figure 4

Conclusion

New oil and gas extraction is both unnecessary for meeting global demand and endangers progress on slowing global climate change. Improvements made through mitigation — increasingly necessary under EU regulations and imperiled by the Trump administration — are undermined by new oil and gas extraction.

The year 2030 — used as a boundary condition for fields’ inclusion in this brief — is an important yardstick for multiple global initiatives to manage methane emissions. Global Methane Pledge signatories have committed to reducing methane emissions by 30% by the end of the decade. Meeting the GMP is estimated to reduce warming by 0.2°C by 2050 and prevent 255,000 premature deaths. Additionally, the new EU methane regulations, which affect importers and involve enhanced leak detection and repair (LDAR) protocols, measurement-based reporting, bans on routine flaring and venting, and eventually compliance with a methane emission intensity standard, come into full effect in 2030.

New oil and gas fields in development are raising the stakes for mitigation efforts worldwide. These fields are coming online amidst a patchy monitoring and data transparency landscape, and most are reaching their peak production capacity during an uncertain time for global environmental commitments and before the EU methane regulations come into full effect. Even though monitoring technologies are improving and companies are making enhanced management commitments, the continued development of these fields unnecessarily risks global climate change mitigation efforts.

Methodology

The February 2025 version of GEM’s Global Oil and Gas Extraction Tracker (GOGET) identifies fields currently in development, including data on field status and when fields are expected to reach peak production. Importantly, GOGET includes data on nine other fields in development which are expected to begin or reach peak production between 2025 and 2030. These were not included in this analysis because they do not report their production design capacity: Either the fields do not publicly report any production data at all or they provide a reserve figure which is incompatible with an annual emissions estimate. Per GOGET, the definition of an “in development” field is as follows:

“A company is planning to develop the project, as evidenced by one or more of the following criteria being reached: the company has applied for approval for commercial production (if needed in the jurisdiction), the project has reached the Final Investment Decision (FID), a final environmental impact statement has been published, and/or the drilling of development (not appraisal) wells and/or adding takeaway capacity (infrastructure such as pipelines, storage tanks, etc.) to enable commercial production has begun.” Fields where researchers could not find information on one of these categories were reverted to the “discovery” category. For details on which fields were reverted to the “discovery” category, see the data supplement.

To estimate emissions, the production design capacity figures were multiplied against proxy emissions factors (“proxies”) identified in the latest publicly available version of OCI+ (as of June 4th, 2025). Specifically, we selected the OCI+ emissions factor for upstream methane intensity, in order to directly represent emissions from production, rather than from processing or transport. Proxy emissions factors were chosen for two reasons: 1) Broadly, OCI+ does not contain data on fields in development; 2) As detailed in the methodology for the Global Methane Emitters Tracker, fields in the OCI+ database do not always share a definition with GOGET, though alignment is high for conventional fields, less so for unconventional fields in the U.S. and Canada; 3) Running the models underlying OCI+ requires inputs which are not generally publicly available for fields in development. Proxies were selected on a few bases. First, if the GOGET asset was an expansion of an existing asset in the OCI+ database (e.g. the GOGET unit “Zuluf Expansion” and the OCI+ unit “Zuluf”), the emissions factor for the existing OCI+ asset was used. Name matches were confirmed to be within ~5 km geographic proximity. If a GOGET asset did not match an OCI+ asset by name, it was matched manually by a combination of location, onshore/offshore, resource type (e.g. oil, gas, or condensate), and operator. Where multiple OCI+ assets were similar quality matches, the field with the lowest upstream methane intensity was chosen to ensure a conservative approach. The list of proxy emissions factors used can be found in the data supplement. Note that some proxies changed emissions factors or were removed from the current (June 4th, 2025) publicly available version of OCI+ and the iteration public at the time of the previous Mixed Message briefing. For fields which were only included in the previous iteration, the OCI+ proxies were kept the same. Otherwise, all fields were updated to current emissions factors.

The fields produce a mix of oil, gas, and condensate. Volumes for natural gas were converted to barrels of oil equivalent (BOE) using the Statistical Review of World Energy conversion factors. Barrels of condensate (or “oil and condensate”) were treated as BOE without further conversion. A note that for some fields with missing operator data, the parent company was used instead – refer the Global Oil and Gas Extraction Tracker data for complete ownership information.

There are two main limitations with respect to GEM’s approach. The first is that methane leaks are stochastic. Production doesn’t necessarily scale with methane emissions: Low-producing wells can emit disproportionate amounts of methane. The equipment- and component-level statistical models underlying OCI+ can match top-down estimates at the field scale. However, many of the key inputs used for running OCI+ (well counts, methane mole fraction, gas-to-oil ratio, and others) are often proprietary, particularly outside of the United States. It is reasonable to assume that many of the OCI+ fields GEM has chosen as proxies differ from the GOGET assets in development in these key dimensions. The second main limitation is that GEM chose the latest available emissions factors in OCI+ based on past operational practices — typically from 2022. As discussed above, due to OGMP 2.0 members’ improvements in monitoring, it is very possible that emissions factors across the oil and gas industry as a whole will improve over time.

More information on GEM’s methane related data and analyses can be found on the Global Methane Emitters Tracker (GMET) landing page. GMET provides estimates of fossil fuel emissions at oil and gas and coal extraction sites, natural gas transmission pipelines, proposed projects and reserves, and attribution of remotely-sensed methane plumes. Data underlying this report can be downloaded separately.

*A partnership between Saudi Aramco Gulf Operations Company (AGOC) and Kuwait Gulf Oil Company (KGOC), a subsidiary of Kuwait Petroleum Corporation

About the Global Methane Emitters Tracker 

The Global Methane Emitters Tracker (GMET) provides estimates of fossil fuel emissions at oil, gas, and coal extraction sites; natural gas transmission pipelines; proposed projects and reserves; and attribution of remotely-sensed methane plumes.

As of the September 2024 data update, the tracker includes methane emissions estimates for coal extraction and gas pipelines and attributions of remotely-sensed methane plume observations worldwide. GMET also associates assets from GEM’s Oil & Gas Extraction Tracker to the methane emissions estimates developed by Climate TRACE.

Media Contact

Sarah Lerman-Sinkoff

Research Analyst, Methane

sarah.lerman.sinkoff@globalenergymonitor.org

The post The next methane surge appeared first on Global Energy Monitor.

On May 21, the government of Honduras announced that it was joining the Powering Past Coal Alliance (PPCA), a coalition of governments and others committed to transitioning away from coal – with the most prominent member being the UK, which retired its last coal plant in 2024. The entry of Honduras into the PPCA implies a cancellation of its last coal plant proposal, the 0.1 GW Puente Alto Energy power station, which has not seen any notable developments since its announcement in 2022. 

Similarly, Brazil’s last active coal plant proposal – the 0.6 GW Pedra Altas power station – was considered shelved in GEM’s Q1 2025 update as there has been no movement on the plant’s licensing since August 2023, when the plant’s Risk Management Program and Emergency Response Plan were rejected by Brazil’s environmental authority, IBAMA. There are also no new coal plants proposed in Brazil’s national energy auctions this year, with a decrease in coal power generation projected through 2034 in the country’s most recent ten year energy plan.

The shelving of Latin America’s last two coal plant projects marks a broader decline in coal power development across the region. No coal plant proposals in Latin America have advanced in the permitting process since 2019, nor has any new construction begun since 2016. 

The one coal plant still under construction in the region, Argentina’s long-delayed Río Turbio power station, remains mired in technical difficulties, cost overruns, and allegations of corruption. 

The Latin America region is also nearly on track to meet the 1.5°C target of the Paris Climate Agreement, which requires a global phaseout of unabated coal power by 2040, according to the IEA’s Net Zero scenario. Based on planned retirements and phaseout commitments, over 60% (10 GW) of the region’s 16.3 GW of operating coal power capacity is scheduled to come offline by 2040.

Remaining coal plants without a retirement date are concentrated in Mexico (4 GW), the Dominican Republic (1.1 GW), and Brazil (0.6 GW). Both Mexico and the Dominican Republic are PPCA members, but have yet to set a coal phaseout date.

With no active coal proposals in Latin America and Brazil hosting the COP30 climate talks this year, the region is in a prime position to lead the charge in the global coal-to-clean energy transition – and help keep the Paris Climate Agreement on track.

About the Global Coal Plant Tracker

The Global Coal Plant Tracker provides information on coal-fired power units from around the world generating 30 megawatts and above. It catalogs every operating coal-fired generating unit, every new unit proposed since 2010, and every unit retired since 2000. The map and underlying data is updated bi-annually, around January and July. Around April and October, partial supplemental releases also cover updates to proposed coal units outside of China.

Media Contact

Christine Shearer

Project Manager, Global Coal Plant Tracker

christine.shearer@globalenergymonitor.org

The post Latin America shelves last new coal plant plans appeared first on Global Energy Monitor.

Evaluating progress toward 2030 iron and steel decarbonization goals

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Pedal to the Metal is an annual survey of the current and developing global iron and steel plant fleet. The report examines the status of the iron and steel sector compared to global decarbonization roadmaps and corporate and country level net zero pledges. 

This year’s analysis draws from GEM’s Global Iron and Steel Tracker (GIST) — formerly the Global Steel Plant Tracker and Global Blast Furnace Tracker — and the Global Iron Ore Mines Tracker (GIOMT). Together, these tools provide detailed, asset-level data on over 1,200 plants and nearly 900 iron ore mines worldwide.

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Cleaner technologies are rising, but coal still dominates

Electric arc furnace (EAF) capacity has grown nearly 11% since 2020, with another 24% increase projected by 2030. Half of all steelmaking capacity under development plans to use EAF technology, much of it integrated with direct reduced iron (DRI) — a process that uses gas, rather than coal, to produce iron before it’s melted into steel in an EAF.

DRI also represents a growing share of new ironmaking capacity, rising to 42% of developments, compared to just 10% of current operating capacity.

If current developments and retirements proceed, the global fleet could reach 36% EAF steelmaking by 2030, just shy of the IEA’s 37% target — a key benchmark for greening one of the world’s most polluting industries. Whether that milestone is met will depend largely on India’s direction.

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India’s choices will shape the future of steel

India’s choices will be decisive in determining whether the global steel sector reaches 37% electric arc furnace (EAF) production by 2030 as the country now dominates global steel development plans.

India has overtaken China as the top developer of new steel capacity and now accounts for 57% of all coal-based BOF capacity under development. Its total steel development pipeline stands at 352 mtpa, more than a third of the global total — yet only 8% of these projects have entered construction. By contrast, China has already begun construction on 46% of its development pipeline.

Much of India’s steel buildout remains concentrated in coal-based technologies. The country also has significant coal-based rotary kiln DRI capacity — much of it at smaller plants not tracked in GEM’s dataset — further compounding its emissions profile. Despite growing international and domestic awareness of the need for clean steel, India has yet to translate that urgency into concrete action.

This gap between ambition and execution presents a turning point. India’s buildout of new coal-based capacity risks locking in decades of emissions — but with much of this capacity still in early planning stages, there’s an opportunity to pivot toward lower-emissions pathways.

India is now the bellwether of global steel decarbonisation. If the country does not increase its plans for green steel production, the entire sector will miss an important milestone. So goes India, so goes the world.

Astrid Grigsby-Schulte, Project Manager of the Global Iron and Steel Tracker at Global Energy Monitor

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Cleaner steel plans advance, but construction lags behind

While India’s trajectory looms large, the broader picture shows that global plans for cleaner steelmaking are growing — even if implementation is still lagging.

Many upcoming projects include integrated direct reduced iron (DRI) and electric arc furnace (EAF) production. DRI now accounts for 42% of ironmaking developments — a notable rise from earlier in the decade. Even so, DRI development has fallen behind global decarbonization goals.

While EAF-based capacity now makes up 50% of all projects in development, less than a third of that is under construction. Meanwhile, 46% of steel projects that have broken ground are still BOF-based, showing that emissions-heavy infrastructure is still advancing.

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Australia and Brazil have a green ironmaking opportunity

While much of the global spotlight is on India, other countries also hold outsized influence in shaping the trajectory of clean steel — particularly upstream in the supply chain.

GEM’s Global Iron Ore Mines Tracker (GIOMT), launched in 2024, maps nearly 900 iron ore mines and underscores how Australia and Brazil are uniquely positioned to shape the future of green ironmaking due to their large iron ore reserves and renewable energy potential. Both countries have large reserves of high-grade iron ore and significant renewable energy potential — key ingredients for green DRI-EAF steelmaking.

But neither country has yet emerged as a leader in green ironmaking. Despite their production advantages, both lag in deploying cleaner technologies like DRI — leaving untapped potential to drive a global shift.

With falling demand from China and growing international momentum for cleaner steel, these countries face both a challenge and an opportunity: align mining and industrial development with the decarbonization of steel, or risk losing competitive ground.

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The pipeline for cleaner steel has never been stronger, with record-high levels of EAF and DRI capacity in development. But unless those projects are built, and built with low-carbon inputs, the industry risks missing its moment.

Cleaner technology is no longer theoretical — it’s available. The coming years will determine whether the steel sector seizes that momentum, or lets it slip.

The post Pedal to the Metal 2025 appeared first on Global Energy Monitor.

• 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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Fossil-powered capacity dropped below half of the electricity mix in the BRICS group for the first time in 2024. However, the expansion of the BRICS group in early 2025 includes relative newcomers to the energy transition, many of which risk staying dependent on fossil fuels. These new BRICS members have ten times as much carbon-intensive capacity under construction as wind and utility-scale solar. Chinese state-owned enterprises play a crucial role in this power sector buildout, backing nearly two-thirds of power projects underway across the new bloc members, including the overwhelming share of their coal (88%) and hydropower (93%).

Key points

• Fossil-powered capacity dropped below half of the total mix in the BRICS group for the first time in 2024
• New BRICS members are building over ten times as much coal, oil, and gas capacity (25 gigawatts (GW)) as wind and utility-scale solar (2.3 GW).
• Over 97% of wind and utility-scale solar capacity among new BRICS members is in the early stages of project development, compared to 30% of fossil projects. Hydropower and geothermal projects see higher construction rates but still fall short of those for coal, oil, and gas.
• Chinese state-owned enterprises (SOEs) have backed over 60% of the total power capacity under construction in new BRICS member geographies and over 90% of hydropower under construction. Despite past pledges to end support of overseas coal projects, Chinese finance and construction still backs 7.7 GW of new coal, virtually all of which is found in Indonesia.

Fossil share of total power capacity in the BRICS fell below half in 2024

The BRICS crossed an inflection point in 2024: fossil fuels no longer account for the majority of their total power capacity. The milestone came on the back of unprecedented renewable energy growth in China, India, and Brazil, mostly from solar and wind technologies. South Africa fell short of the record solar capacity additions seen in 2023 but still saw solar and wind additions surpass 800 megawatts (MW) of new coal-fired capacity from the long-delayed Kusile power station. Russia remained largely static and still anchored in fossil generation.

Members of the bloc joining in 2024 saw capacity additions similarly tilted towards non-fossil additions. Egypt solidified its second-place ranking in Africa for renewable capacity, with 1 gigawatts (GW) of solar and wind capacity added in 2024. The United Arab Emirates led the Middle East region’s solar capacity additions in 2024. Ethiopia cemented hydropower’s primacy as additional turbines of the Grand Ethiopian Renaissance hydroelectric plant became operational last year.

Figure 1

New BRICS members are building over ten times as much fossil capacity as wind and utility-scale solar

Alongside the progress of several major BRICS countries in renewables uptake, the recent expansion of the group includes newcomers to the energy transition, many of which could get locked into fossil fuel use. Brazil kicked off this year’s rotating presidency of the BRICS group of nations by announcing Indonesia’s accession to full membership along with nine additional countries obtaining partner status, including Belarus, Bolivia, Kazakhstan, Cuba, Malaysia, Thailand, Uganda, Uzbekistan, and Nigeria.¹ The BRICS expansion brings major coal- and gas-producing and consuming nations into the group. Indonesia and Kazakhstan are among the world’s top ten coal producers and exporters, with power sectors reliant on coal for over 60% of electricity generation, and Malaysia, Thailand, and Uzbekistan have sizable domestic coal mining activities and growing imports. According to Global Energy Monitor (GEM) data, the expansion of the BRICS group means that 94% of global construction and pre-construction coal plant capacity is now held within BRICS. The addition of new members to the bloc increases the BRICS share of global operating coal plant capacity by 6% and boosts the BRICS share of the global coal development pipeline by 3%.

All but one of the new BRICS members are oil and gas producers,² with each of the four largest producers (Nigeria, Kazakhstan, Indonesia, and Malaysia) planning further development of new and existing fields. These new members all use oil and gas for power generation, and GEM data show seven of the ten new members have new oil and gas plant capacity in development, totalling 63 GW of capacity. These new members increase the BRICS share of oil and gas plant capacity in development by 26% to total 40% of the global amount.

Despite the general dominance of fossil fuels among the expanded BRICS group, most members have signaled a willingness to transition away from fossil fuel energy sources. Currently, eight out of the ten new members have declared some form of net-zero emissions target in the 2050–2070 time frame, and all five of the new members that use coal for power have publicized some form of coal plant phaseout date (see accompanying GEM Wiki page for a compilation of net-zero pledges and phase out announcements). These targets, in their various forms, would all involve a wholesale transition away from fossil power to non-fossil sources — comprising large shares of wind and solar power.

But there is distance between intentions and actions within the power sector transition. GEM’s Global Integrated Power Tracker shows that although all new members of the BRICS group have 139 GW of non-fossil power capacity in development, including solar, wind, hydropower, geothermal, and nuclear, just 7%, or 10 GW, of this total is under construction. By comparison, new fossil capacity sees a much higher rate of construction among the newest BRICS members, with 44% of coal plants and 26% of oil and gas plants in the construction phase.

Although the total figure for fossil capacity in development is lower than for non-fossil, the higher rate of construction implies that more than twice as much coal, oil, and gas capacity is currently getting built in new BRICS member geographies (25 GW vs. 10 GW). More concerning still are the markedly low levels of wind and utility-scale solar capacity in the construction phase — two cornerstone technologies of the energy transition. According to GEM data, nine of the ten new BRICS members have less than 0.3 GW of wind or utility-scale solar capacity under construction. Contrasting these members with China, India, and Brazil — frontrunners in wind and solar capacity with record 2024 deployment — new BRICS members need a major ramp up in renewables construction activities to shift the fossil dominance.

Figure 2

Chinese state-owned enterprises drive power sector expansion in new BRICS countries

Chinese state-owned enterprises (SOE) have widespread involvement in the financing and construction of BRICS power projects overseas. The new BRICS members have a total of 35 GW of power capacity under construction across energy technologies: coal, oil and gas, hydropower, solar, wind, and geothermal, and GEM’s comprehensive analysis of these under-construction projects indicates that just under two-thirds (62%) of this total capacity under construction involves Chinese SOEs, either as providers of engineering, procurement, and construction services (EPC) and/or as financiers. This share of Chinese involvement is even greater in hydropower and coal power projects, at 93% and 88%, respectively.

China’s reach is part of larger trends: The country’s outward direct investments climbed 10% in 2024, with annual cleantech investment double that of either the U.S. or EU. China’s outbound investment program under the Belt and Road Initiative (BRI) saw its highest-ever level of investment and construction contract value in 2024. Notably, all new BRICS members are part of the BRI and have seen the effects of the venture’s consistent energy-sector focus, an average of over one-third of all BRI engagement in the last decade.

By far, the largest share of China’s outward investments in the energy sector to date is toward fossil projects. Indonesia was the largest single recipient of investment under BRI in 2024, and almost all of that investment was directed to the energy sector. In recent years, Chinese-origin finance has been instrumental in the growth of captive coal plants, particularly for metal ore refining, with Chinese-led captive coal capacity tripling since 2019. Further capacity additions are planned in Indonesia, with 8.6 GW of coal plants currently under construction, 88% of which include beneficial ownership from Chinese SOEs. Chinese SOEs are also involved in developing 6.5 GW of oil and gas power capacity across seven plants in new BRICS member geographies, with the largest plants in Uzbekistan and Nigeria.

Chinese involvement is even more extensive in hydropower projects, especially those under construction in new BRICS member geographies. Virtually all of Indonesia’s under-construction hydropower capacity³ involves Chinese firms for EPC purposes, including a subsidiary of the state-owned China Energy Engineering Corporation (CEEC) working on the Upper Cisokan plant, Indonesia’s first pumped storage facility. In Malaysia, a subsidiary of CECC is also undertaking the main civil works for the 1.3 GW Baleh hydroelectric plant, with three further recently commissioned projects by Chinese SOEs (Bakun-PowerChina, Murum-Three Gorges, and Perak-CEEC). China Southern Power Grid is developing the Pskem pumped storage plant in Uzbekistan, and has signed agreements for three additional hydroelectric projects, all due for completion by 2030. Nigeria’s 3 GW under-construction Mambilla hydropower project is 85% financed by China Exim Bank, which is also financing the planned 360 MW Gurara II hydropower project and the recently commissioned 700 MW Zungeru and 130 MW Kandadji projects. Sinohydro Corporation is the lead contractor for the 1 GW Makurdi hydropower project in Nigeria. With financing from China Exim Bank, Sinohydro Corporation also financed the recently commissioned 600 MW Karuma hydropower project in Uganda, with a further three announced hydropower projects also receiving Chinese backing. The Laos Pak Beng hydropower project will export all power to Thailand and is 51% owned by China Datang Overseas. And in Bolivia, the Rositas 600 MW hydropower project received support from China Exim bank and a consortium of Chinese construction SOEs.

A combination of factors likely contributed to China’s SOEs favouring large power projects overseas in recent years, including coal and hydroelectric developers seeking new opportunities due to slackening domestic demand, and direct instruction for policy banks to support BRI-type lending abroad. Following the criticism of some overseas energy projects for environmental failures, outward investment policy advocated for a green shift, notably the 2021 announcement to cease building new coal plants abroad and instead step up investment in renewable energy. The continued backing of captive coal plants and mining projects abroad in the years since attests to apparent loopholes in the moratorium. Nonetheless, China has redoubled commitments to greener investments abroad, refocusing on smaller, sustainable projects, and has recapitalized policy banks.

Meanwhile, China’s increasingly renewables-focused SOEs and industry-leading private firms are seeking to expand their global footprint, with outbound capital flows into solar, wind, batteries, and new energy vehicles at historically unprecedented levels. These trends are apparent in GEM data, with several new BRICS members showing significant projects in early-stage development, most notably in Uzbekistan, with all under-construction solar and wind farms involving Chinese SOEs. Indonesia and Malaysia have solar projects in early stages of development totalling over 3 GW each, again with Chinese SOEs leading EPC roles. Chinese firms also lead construction of Kazakhstan’s largest wind farm and a project to provide 2 GW of solar capacity to Cuba.

Several namesake BRICS nations have seen record deployment of wind and solar in recent years, and new members stand to gain from cultivating ties with the bloc to secure investment, know-how, and low-cost supply in these critical technologies. Other BRICS countries not yet seeing this uptick should heed the broader positive experiences of energy transition in the Global South, where the acceleration of solar and wind’s share of electricity generation has far outpaced historical precedents.

Figure 3

¹ The official website of the Brazilian Presidency currently lists Saudi Arabia as a full member, though Riyadh has not officially accepted the invitation, so Saudi Arabia is excluded here.

² Uganda will commence oil production in 2026–2027.

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

About the Global Integrated Power Tracker

The Global Integrated Power Tracker (GIPT) is a free-to-use Creative Commons database of over 142,000 power units globally, that draws from GEM trackers for coal, gas, oil, hydropower, utility-scale solar, wind, nuclear, bioenergy, and geothermal, as well as energy ownership. Footnoted wiki pages accompany all power facilities included in the GIPT, updated biannually. For more information on the data collection process that underpins GEM’s power sector trackers, please refer to the Global Integrated Power Tracker methodology page.

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, and Bluesky @globalenergymon.bsky.social.

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Boom and Bust is an annual survey of the global coal fleet by Global Energy Monitor and partners. The report analyzes key trends in coal power capacity and tracks various stages of capacity development including planned retirements. This provides key insights into the status of the global phaseout of coal power and evaluates progress towards the world’s climate targets and commitments. 

The data comes from GEM’s Global Coal Plant Tracker, an online database updated biannually, with partial quarterly supplements, that identifies and maps every known coal-fired generating unit and every new unit proposed since January 1, 2010 (30 MW and larger). 

Global Energy Monitor’s data serves as a vital international reference point used by organizations including the Intergovernmental Panel on Climate Change, International Energy Agency, and the United Nations, as well as global media outlets.

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In 2024, global coal power additions dropped to their lowest level in 20 years, yet the world’s coal fleet continued to grow, according to Global Energy Monitor’s annual survey of the global coal fleet.

Data from the Global Coal Plant Tracker show that 44.1 gigawatts (GW) of coal power capacity was commissioned while 25.2 GW was retired in 2024, resulting in a net increase of 18.8 GW. The capacity commissioned was nearly 30 GW below the annual average for 2004 to 2024 (72 GW) — a sign of the continued slowdown in global coal construction.

Even so, retirements have not kept pace with new additions. Global coal capacity rose to 2,175 GW, up 259 GW since the Paris Agreement was signed in 2015. Most of this growth came from China, which commissioned 30.5 GW of coal power capacity in 2024 — 70% of the global total — and saw 94.5 GW in new construction starts, the highest in nearly a decade.

Outside China, coal power capacity decreased by 9.2 GW, as retirements (22.8 GW) exceeded new additions (13.5 GW) in the rest of the world. In the EU27, retirements quadrupled year over year, reaching 11 GW, while the UK shut down its last coal plant, becoming the sixth country to complete a coal phaseout since 2015.

But elsewhere, progress stalled. Retirements slowed in the United States, falling to 4.7 GW — the country’s lowest level in a decade. At the same time, India recorded its highest-ever level of new coal proposals, totaling 38.4 GW. But outside of China and India, new proposals fell to just 8.8 GW — the lowest level since 2015 — highlighting a continued contraction of the coal project pipeline across most of the world.

As new proposals have declined globally, coal development has become increasingly concentrated in fewer countries. Just ten countries now account for 96% of coal power capacity under development, with China and India alone responsible for 87%. This consolidation reflects the accelerating exit from coal in much of the world, even as a small group of countries continues to pursue large-scale expansion.

In the 38 countries comprising the Organization for Economic Cooperation and Development (OECD), the shift away from coal has been especially pronounced: The number of coal plant proposals has dropped from 142 in 2015 to just five today. But despite this progress, coal retirements in OECD countries need to more than triple — from 19 GW to 70 GW annually — to align with the Paris Agreement.

Coal power set records last year but not the ones industry would like to see. Last year was a harbinger of things to come for coal as the clean energy transition moves full speed ahead. But work is still needed to ensure coal power is phased out in line with the Paris climate agreement, particularly in the world’s wealthiest nations.

Christine Shearer, Project Manager of Global Energy Monitor’s Global Coal Plant Tracker

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Coal exits gather speed in Europe, while major economies fall behind

Retirements surged in Europe in 2024, with the EU27 retiring 11 GW of coal capacity — a fourfold increase over 2023. Germany led the way, retiring 6.7 GW, while the United Kingdom completed its coal phaseout — a key milestone in Europe’s broader shift away from coal. These shifts underscore the accelerating pace of coal retirements across much of Europe.

All but three EU countries are now planning to be coal-free by 2033, and both Ireland and Spain are expected to complete their phaseouts in 2025. Still, at least seven EU countries have timelines that will need to be accelerated to meet the goals of the Paris Agreement.

But elsewhere, progress was far less consistent. In the United States, coal retirements fell to 4.7 GW, the country’s lowest annual total since 2014. The slowdown extends a trend that began in 2021, as fewer plants are being scheduled for closure and more retirements face delays.

Coal plant retirements in the U.S. are expected to pick up over the next few years. Despite the Trump administration’s support for coal, more coal was retired during Trump’s first term than under Obama or Biden — a trend that is set to continue.

Meanwhile, China’s retirements remained minimal, leaving the country off track to meet its 30 GW retirement goal under the current 14th Five-Year Plan (2021–2025). With far more plants being added than taken offline, China’s coal fleet continued to expand — underscoring the challenge of achieving net reductions without a formal phaseout policy.

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China and India defy the global coal decline

While most of the world moved away from coal in 2024, China and India continued to drive large-scale development, expanding their coal pipelines even as many other countries backed away.

In China, a surge in construction activity followed an unprecedented permitting boom in 2022 and 2023, during which more than 200 GW of coal capacity was approved — more than the size of the entire U.S. coal fleet. In 2024, 94.5 GW of that capacity moved into construction, the country’s highest level of construction starts since 2015.

If not curtailed, this wave of new coal plants could undermine President Xi Jinping’s pledge to strictly limit the growth in coal consumption by 2025.

Meanwhile, India proposed 38.4 GW of new coal power in 2024 — the highest annual total on record. The country plans to build more than 90 GW of new coal by 2032, even as it targets 500 GW of non-fossil capacity by 2030.

Although many countries have now committed to phasing out coal, the ongoing expansion in China and India threatens to offset global progress.

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Outside Asia’s giants, momentum toward phaseout grows

In Southeast Asia, several countries are moving toward a managed exit from coal. New proposals have dwindled across the region, driven by phaseout pledges in Indonesia and Malaysia, a moratorium on coal plant permitting in the Philippines, and the development of just transition planning in Vietnam.

Indonesia presents a more complicated picture. While the country appears on track to retire 9.2 GW of coal by 2030, and President Prabowo has pledged to phase out coal power by 2040, a major challenge is emerging: the rapid growth of captive coal plants — those supplying electricity directly to industrial facilities. These plants fall outside the grid-based retirement pledges and risk repeating the pattern of the past decade’s buildout: overcapacity, cost overruns, and controversy.

Meanwhile, in Turkiye, coal power expansion has nearly ground to a halt, as the country’s pipeline of new proposals has collapsed — leaving just one remaining project (0.7 GW). This puts the country on the verge of joining other OECD nations in eliminating all unabated coal plant proposals.

In Latin America, countries are approaching a full exit from coal. Only Brazil and Honduras still have coal proposals on the books, and even those have lingered for years without progress. In 2024, Panama committed to phasing out coal power by 2026, joining a growing group of countries in the region moving toward coal-free electricity.

But while most of Latin America is phasing out coal, Brazil remains home to the last coal plant proposal over 100 megawatts in Latin America, and its coal subsidies are drawing growing criticism. Brazilian ratepayers are set to spend R$8 billion (US$1 billion) between 2020 and 2027 to support just two coal plants, with the Brazilian Congress currently debating a R$92 billion (US$16 billion) extension through 2050. These measures risk locking in coal for decades, despite clear regional momentum in the opposite direction.

In Africa, coal development remains limited but not absent. Most countries in the region are prioritizing renewables and gas, and no new coal plants were commissioned in 2024. Still, new proposals emerged in Zimbabwe and Zambia, largely backed by Chinese developers — despite the Chinese government’s 2021 pledge to stop building new coal plants overseas. These projects stand out as exceptions in a region where coal activity has stalled, and raise concerns about fossil fuel lock-in in emerging energy systems.

While most OECD countries have moved away from coal, Japan and South Korea remain notable holdouts. Both countries continued to build and plan new coal plants in 2024, placing them increasingly out of step with international climate commitments and the broader shift among high-income economies.

In an effort to justify ongoing coal use, Japan and South Korea jointly agreed in 2024 to promote ammonia co-firing at coal plants as an “emissions reduction” strategy. But this approach has drawn criticism for prolonging the life of coal infrastructure and falling short of what’s needed to align with the Paris Agreement.

Coal phaseouts are lagging where they matter most

While much of the world continues to move away from coal power, the pace of retirements and project cancellations remains far too slow to meet global climate goals.

The divide between progress and continued buildout widened in 2024. Many countries completed or accelerated coal exits, while others ramped up new construction. This uneven trajectory has left the global coal transition off pace for aligning with the Paris Agreement.

Boom and Bust Coal 2025 is a joint effort by Global Energy Monitor, Centre for Research on Energy and Clean Air (CREA), E3G, Reclaim Finance, Sierra Club, Solutions for Our Climate, Kiko Network, Climate Action Network (CAN) Europe, Waterkeepers Bangladesh, Dhoritri Rokhhay Amra (DHORA), Trend Asia, Policy Research Institute for Equitable Development, Chile Sustentable, POLEN Transiciones Justas, Arayara, Bankwatch, INSAPROMA, and Africa Just Transition Network.

The post Boom and Bust Coal 2025 appeared first on Global Energy Monitor.

Key points

• Policies from both the Biden and Trump administrations as well as bipartisan support have created a quicker path to construction for geothermal energy, benefitting more than 4 GW of units in development and aligning with the 2030 Project Liftoff goal of 5GW.
• Robust energy policy in the U.S. necessitates the rapid rollout of the 218.4 GW of prospective capacity for wind and utility-scale solar with geothermal playing a peaker plant role, particularly with heavy energy users like artificial intelligence data centers. 
• Enhanced Geothermal Systems (EGS) technology is becoming increasingly affordable and construction time is decreasing, making it a competitive alternative to the oil and gas industry. There are currently more than 2 GW of EGS power plants in development in the U.S.

Introduction

While the Trump administration has pushed aside renewables like solar and wind, jeopardizing the status of projects in development, geothermal has managed to escape green energy criticism, and now finds itself primed  for explosive growth. Technological advances in geothermal technology — particularly with Enhanced Geothermal Systems (EGS) — have also lowered the cost and construction time of geothermal projects. Bipartisan support for the technology, rapid technological advancements, and increasing investments have put geothermal energy into a position to grow rapidly during the next four years, with 1.16 gigawatts (GW) anticipated to come online by 2028, according to Global Energy Monitor’s Global Geothermal Power Tracker. 

Chris Wright, the new U.S. Secretary of Energy under the Trump administration, signed his first Secretarial Order in early February 2025 calling to “Unleash [the] Golden Era of American Energy Dominance,” which explicitly states support for geothermal energy and heating. Geothermal is on the path to become an important renewable energy source in the U.S.’s energy mix, especially during an artificial intelligence arms race that necessitates 24/7 power availability. Under a Trump 2.0 administration where renewable energy has been pushed to the wayside, geothermal energy has managed to fly under the radar and may actually benefit from a “drill, baby, drill” attitude if it’s not merely an excuse  to subsidize the oil and gas industry.

However, a truly robust energy policy focused on energy independence and security would include the most dominant renewable technologies in the industry today — wind and solar — which could add an additional 122 GW to the U.S. energy matrix by the end of President Trump’s term if these technologies receive adequate support instead of being stonewalled.

The growth of geothermal gains bipartisan support

Geothermal is an industry known for its slow growth, with only 382 megawatts (MW) coming onto the grid worldwide in 2024. As of 2025, the United States accounts for 23% of global geothermal capacity and is the leader in global operating capacity with 3.7 GW. The 2025 update of the Global Geothermal Power Tracker shows 223 units in development, totalling more than 15 GW of capacity, nearly doubling the current global geothermal operating capacity of 16 GW across 480 units. 

Research and development funded by the U.S. Department of Energy (DOE) has worked to prove market opportunity for geothermal power, and DOE aims to reach 5 GW of capacity by 2030 in the first stage of its Liftoff program¹, followed by a 2050 goal of 90 GW of geothermal power. The DOE also aims to slash geothermal’s cost per megawatt hour by 90% by 2035 through the Enhanced Geothermal Shot² initiative.

Bipartisan support for geothermal energy has allowed policies to be put in place which expedite the process of getting a geothermal power plant online. In January 2025, the Inflation Reduction Act was expanded to cover geothermal power through investment and production tax credits. Also in January 2025, the Bureau of Land Management (BLM) authorized the new categorical exclusion that simplifies the permitting of geothermal projects in the United States, potentially saving up to a year of time for a project in development. As of February 2025, the Department of the Interior is proposing to revise the National Environmental Policy Act (NEPA) to obtain an additional categorical exclusion for geothermal energy. 

It remains unclear how the culling of federal employees undertaken by the Department of Government Efficiency (DOGE) will impact the process of getting geothermal power plants online. The erratic nature of the Trump administration makes long-term geothermal plans hard to guarantee, as the goals of the DOGE team change daily. Investors may also be scared off by a volatile economy, social unrest, and rising international tension.

Figure 1

Bipartisan support will continue to be a key element of the exponential growth of geothermal energy in the coming years. President Trump stated in a January 2025 energy emergency declaration that geothermal is important for the diversification of the U.S. energy supply and the administration’s official view — despite it being false — is that geothermal is more “economically viable than wind or solar.” Geothermal energy is not mentioned in Project 2025, which could be interpreted as further evidence of support by the Trump administration. Conversely, the nearly 1,300 prospective wind and utility-scale solar phases are specifically threatened in Project 2025. According to GEM’s March 2025 data release, 1.16 GW of geothermal capacity could come online by the end of Trump’s current term in office. There are also eight geothermal units which are inferred to be cancelled (based on a lack of updates) that could be revived by the friendliness of the administration.

Technological advancements in the geothermal industry

Geothermal can be a viable alternative to gas peaker plants, thereby increasing grid integration of wind and solar’s intermittent power to further bring down emissions. Having geothermal as a dispatchable power source could take the place of costly gas peaker plants and would be a supplement  to batteries. 

A key player in Enhanced Geothermal Systems (EGS) is Fervo Energy, which has a successful pilot project operating in Nevada and 2.1 GW of projects in development; the company is also demonstrating how its wells can be used as giant underground batteries. Fervo has received funding from the U.S. Department of Energy through its Renewable Energy Research and Development program and was notably invested in by Secretary Wright’s company, Liberty Energy, while he was CEO. Fervo Energy is tied for the most prospective megawatts of geothermal capacity worldwide as of March 2025 and accounts for half of the 4.3 GW of U.S. geothermal in development. With a 70% reduction in drilling time per well and a savings of US$5 million per well gained from fine-tuning its technologies, it is likely that Fervo will continue to rapidly expand its portfolio in the United States. If investments in the 85 GW of oil- and gas-fired capacity in development in the United States were shifted to support geothermal development, investors would be funding projects better for the planet.

Figure 2

If geothermal continues to receive support from the Trump administration, stakeholders in the United States can use resources such as the Geothermal Exploration Opportunities Map tool from Project Innerspace to understand where the best opportunities for geothermal development in their area of interest are. As resources for understanding geothermal are made more readily available to the public and green energy investors take note of the friendliness towards geothermal, EGS is likely to see increased investment and rapid deployment.

With exclusions for geothermal energy already being made by the federal government and the Department of Energy granting six $5 million grants to tackle barriers to geothermal development, it is likely the geothermal lease auctions by the BLM taking place during 2025 in Alaska, Nevada, and Utah will see lots of interest. In December 2024, seven parcels were sold during a geothermal lease sale in New Mexico. The U.S. Department of Defense has pre-approved companies to develop utility-scale geothermal projects at DoD installations.

Geothermal energy also stands out as a green energy source to assist the United States in its goal of competing in the AI arms race, which presently has electrical demand rising to meet data centers’ large electricity needs. The continuous energy that geothermal provides makes it a key asset. The support of green geothermal power to meet data center demands in lieu of gas-fired power plants, which are becoming more expensive and slower to deploy, could protect the United States from increased emissions while still providing a constant source of scalable power.

A March 2025 report details how data center electrical demands could largely be met “economically” by geothermal power in the 2030s if such power plants are constructed strategically near data centers. While big tech companies are rarely the outright owners of geothermal power plants, power purchasing agreements (PPAs) between companies to help power data centers — such as by Meta (partnering with Sage Geosystems) and Google — will likely drive demand for these plants to be built, particularly if tech CEOs continue to have President Trump’s ear. With wind and solar threatened, companies striving to meet consumer demands that their data centers be run on green energy will still have geothermal power to turn to and may feel secure upon seeing the success of pilot projects such as Fervo’s Project Red geothermal power plant, which serves Google-owned data centers in Nevada. Energy Secretary Wright stated in March 2025 that a strong geothermal industry “could better energize our country, [and] improve the quality of life for everyone. It could help enable AI, manufacturing, reshoring and stop the rise of our electricity prices.”

It’s unclear how the Trump administration (and Elon Musk’s influence through DOGE) will impact the workflow of new geothermal energy projects seeking authorization. If critical linchpins in the permitting process have been fired, it won’t matter how much investment begins to pour into geothermal projects or how many exclusions these projects receive to speed up processing. This dismantling has the potential to stunt the growth needed by states like Texas that are increasing data centers and cryptocurrency mining and predict a doubling of energy demand by 2030. 

Technological breakthroughs in the geothermal industry continue to happen, notably with EGS technology which has undergone exponential growth in recent years, despite being studied since the 1970s. The advancements are largely due to the hydraulic fracturing techniques which have been fine tuned by the oil and gas industry. This “human-made” geothermal removes the geological restrictions confining conventional geothermal to permeable rocks with water sources and allows for expansive growth throughout the United States. There are risks associated with EGS, such as earthquakes, air and water pollution, and land subsidence.Because the technology’s success is dependent on managing associated risks, EGS technology has benefited from the lessons learned by oil and gas drilling. The oil and gas industries have many synergies with geothermal in both their workforce and the technologies that can be utilized for the geothermal energy rollout. By accessing deeper heat reservoirs through EGS to create geothermal energy, developers can look outside of traditional geographic areas, with underground heat close to the surface, to develop geothermal power plants across the United States. 

The advancements of EGS technology are good news for the clean energy movement in the United States, and by 2030, the cost per megawatt-hour (MWh) could be competitive with conventional power sources. While not under the scope of the Global Geothermal Power Tracker, heating through networked geothermal, domestic lithium production through geothermal brines, and direct use applications are also likely to garner bipartisan support and investment. These additional uses of geothermal would address Chris Wright’s unfounded concerns about losing the “myriad” uses of gas.

Geothermal as a complement to wind and solar

Historically, not all planned projects become operational on time. Existing limitations in the physical grid, permitting bottlenecks, and lack of financial mechanisms are often reasons for low completion rates. GEM data included 185 GW of solar and wind farms that were under construction as of December 2023 and designated to become operational before the end of 2024. Globally, only 59% of these projects started producing electricity on time.

Figure 3

About the Global Geothermal Power Tracker

The Global Geothermal Power Tracker (GGPT) is a worldwide dataset of geothermal power facilities. The GGPT includes geothermal power plant units with capacities of 1 megawatt (MW) or more.

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, X @GlobalEnergyMon, and Bluesky @globalenergymon.bsky.social.

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• 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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Project Manager, Global Oil and Gas Extraction Tracker

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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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• If India replicates last year’s annual wind and solar deployment until the end of the decade, the country’s renewables fleet would expand around 80% to 378 gigawatts (GW), short of its 500 GW target of non-fossil power capacity by 2030.
• Closing this gap with wind and solar would require annual capacity additions to grow year-on-year at about 15%.
• The capacity of utility-scale solar, and hydropower projects in development — those that have been announced or are in the pre-construction and construction phases — is on track to overtake operating coal capacity within the next two years.

India added nearly 35 gigawatts (GW) of power capacity in 2024, setting a new record for the calendar year. Solar photovoltaic (PV) capacity made up 71% of all additions across the power sector, a record annual capacity addition for any technology in the country.

Global Energy Monitor’s latest data from the Global Integrated Power Tracker indicate a robust pipeline of renewables¹ projects set to come online, with the combined capacity of wind, utility-scale solar, and hydropower in development on track to overtake operating coal capacity within the next two years. Utility-scale solar projects comprise nearly half of all renewables in development, with more capacity in the construction phase than for coal projects.

Yet, despite the strong year, renewables only made up around one-fifth of the total increase in power generation in 2024, with fossil power contributing more than two-thirds. Accelerating the rollout of renewable sources is essential to reverse the rise in fossil generation and to meet India’s ambitious 500 GW of non-fossil power capacity by 2030, which requires annual deployment to double over the next five years.

A record year for capacity additions in the Indian power sector

The Indian power sector reached its highest-ever levels of annual capacity additions in 2024 with 34.7 GW, exceeding the previous record year in 2015 by 3.5 GW. The capacity additions in 2024 comprise mostly renewables, compared to majority coal plant additions a decade ago.

The net fossil capacity additions of 5.6 GW in 2024 were less than one-quarter that of their peak year in 2014. Coal plants made up all of these fossil additions in 2024, with virtually no change in the oil and gas plant fleet. Although down from previous record highs in the mid-2000s, net coal plant additions in 2024 were the highest since 2019, maintaining a five-year high.

India’s power capacity additions aim to meet growing domestic electricity demand, which has burgeoned in the economic rebound following Covid lockdowns and intense summer heat waves that drive cooling-related demand. Although electricity demand growth attenuated in the second half of 2024, largely due to weakening industrial performance, projections for 2025 foresee a return to 5–7% growth, double the global average.

The Indian Government’s pursuit of new power capacity is all encompassing. In fossil-powered sectors, the Indian government has redoubled support and fast-tracked the development of large coal plants, with the pipeline of coal plant proposals growing 45% in 2024 to reach 111 GW total capacity in development. For renewables, capacity additions have been bolstered by ambitious renewables purchase obligations for power distribution companies and tenders targeting 50 GW of new capacity per year.

Figure 1

Solar power propels capacity growth

India’s record year for capacity additions was propelled by solar photovoltaic technologies, which accounted for 71% of total capacity additions across the power sector and 86% of the 28.6 GW of renewable capacity additions in 2024.

Solar PV additions in 2024 (24.5 GW) are more than those in 2022 and 2023 combined and mainly comprise ground-mounted utility-scale solar (75%). However, small-scale distributed solar also made impressive gains, spurred by a new government subsidy scheme for households that has seen 700,000 installations since its launch.

Wind capacity additions of 3.4 GW in 2024 were about a third higher than the average annual deployment over the last decade. But they fell below the record annual deployments of 2016 and 2017. A combination of factors has slowed the wind sector in recent years, including supply chain constraints, land acquisition and rights issues, and an unsustainable tariff system. Still, the steady pace of wind deployment saw cumulative operating wind capacity reach 48 GW by the end of 2024, overtaking large-scale hydropower to become India’s third-largest power source by operating capacity, behind solar and coal.

Capacity additions in 2024 for hydropower and bioenergy were 0.7 GW, or less than 2% of the year’s total renewable additions.

Figure 2

Indian states chart their own paths on renewables expansion

The locations of solar and wind installations operating in India largely reflect the country’s varied physical resources and differing state-level support policies. This is particularly apparent for the country’s wind farms, which cluster almost exclusively within the so-called seven “windy states” on the western side of the country. Half of the operating wind capacity nationwide is found in two of India’s states: Gujarat in the northwest (12.5 GW), with favorable low-lying coastal land, and Tamil Nadu in the South (11.4 GW), where wind farms cluster around mountain passes of the Western Ghats range.

Utility-scale solar farms are more widespread than wind farms, clustering around the best solar resources in the northwest. The northwestern state of Rajasthan hosts a considerable grouping, some 27% (26.5 GW) of the total India solar PV fleet. The vast expanse of the Thar desert holds around three-quarters of the state total, including the 2.7 GW Bhadla complex, one of the largest solar PV sites in the world.

Wind and solar installations are notably less prevalent in India’s far north and northeast. The mountainous terrain, lower wind speeds, and fewer sunshine days may limit the large-scale deployment of wind and solar technologies in these regions. However, hydropower is a significant power source within the Himalayan foothills, accounting for over 80% of total capacity in five northern states.

Figure 3

In 2024, the leading states for wind and solar deployment further extended their precedence. Specifically, six states accounted for 89% of the 2024 wind and solar additions (Rajasthan, Gujarat, Maharashtra, Tamil Nadu, Madhya Pradesh, and Karnataka) and together now account for two-thirds of all renewable energy capacity nationwide. Several of these leading states also registered impressive gains for renewable generation — notably Rajasthan, where solar added more generation than any other source in 2024.

Figure 4

However, the gains of the frontrunner states are not enough to change the fossil-dominated picture nationwide. Data from the Central Electricity Authority show fossil sources covering two-thirds of the year-on-year increase in electricity generation, maintaining a 75% share of the total. These gains were primarily due to the increasing deployment of the existing coal fleet, with utilization rates averaging close to 70% throughout the year, their highest in a decade. Solar energy covered approximately one-fifth of the 2024 increase in electricity generation in 2024. Wind generation was nearly the same as last year, despite new wind farms increasing India’s operating wind fleet by ~8% over levels in 2023, likely due to particularly weak monsoon winds during August 2024.

Doubling wind and solar annual deployment necessary to hit renewables targets by 2030

GEM’s Global Integrated Power Tracker shows power projects in development — those that have been announced or are in the pre-construction and construction phases — spanning a wide range of sources in India. Coal leads the pack, with 111 GW of capacity in development, 29.5 GW of which is under construction, which corresponds with the Ministry of Power’s plans for an additional 80 GW of coal power in the fiscal year 2031–32.

The capacity of utility-scale solar projects in development closely follows coal (103 GW), with more capacity in the construction phase (30 GW). Wind capacity in development (20 GW) is notably lower than for utility-scale solar but projects slated for commissioning in 2025 would constitute an increase over last year’s new capacity if built on time.

According to GEM data, the proportion of in-development wind and utility-scale solar projects that have reached the construction phase exceeds 30%, among the highest values globally. The relatively high construction rate and large project pipelines for utility-scale wind is indicative of continued capacity growth and tallies industry projections showing growing solar and wind additions over the next two years.

GEM data also show that, by 2030, 17 GW of hydropower and pumped storage capacity currently under construction will come online, over three-quarters of which is located in north and northeastern regions. Pumped storage is increasingly looked to as an energy storage option to facilitate the integration of massive wind and solar additions and ensure grid stability. Current plans for new nuclear power plants target an additional 11 GW capacity by 2030, providing an annual generation equivalent to about two years of new solar capacity additions (60 GW).

Figure 5

In 2024, coal’s share of total power capacity fell below 50% for the first time since the 1960s. Renewables alone will likely eclipse operational coal capacity within the next two years, if wind and solar capacity additions replicate similar record levels of deployment (~30 GW), and under-construction hydropower projects come online to schedule (~5 GW). At similar levels to the 2024 deployment, solar will likely overtake hydropower to become the second-largest power source next year after coal.

However, a significant uptick in renewables deployment is required for these sources to expand upon their current one-fifth share of total generation and to eat into coal’s dominance. This is because renewables tend to generate less readily than fossil sources: Wind and solar have an average utilization rate of 17–22% across the year, compared to coal’s 70%.

Replicating 2024’s annual wind and solar deployment to 2030 would expand India’s renewables fleet by around 80% to 378 GW. GEM’s Global Integrated Power Tracker shows an additional 24 GW of hydropower capacity slated to come online by 2030. That would leave about a 100 GW shortfall to India’s target of reaching 500 GW of non-fossil power capacity by 2030. Closing this gap with wind and solar would require annual capacity additions to average 60% higher than the additions in 2024 or grow year-on-year at about 15%. Post-pandemic wind and solar growth rates have tracked slightly above this level, suggesting that renewables expansion in line with the 500 GW target is attainable if the recent pace of growth can be maintained. Such growth would see annual wind and solar additions more than double the record levels in 2024 by 2030.

Realizing this level of renewables expansion will require navigating numerous challenges. Infrastructure challenges include lacking electricity transmission and energy storage capacity. Regulatory and finance challenges chiefly involve tackling widespread non-compliance with renewables purchasing obligations and the high financing costs to project developers in India. There are additional challenges related to just transition, encompassing conflicts over farmers’ and local community’s rights to access land, as well as livelihood impacts on those employed in coal-related industries.

Figure 6

About the Global Integrated Power Tracker

The Global Integrated Power Tracker (GIPT) is a free-to-use Creative Commons database of over 116,000 power units globally, that draws from GEM trackers for coal, gas, oil, hydropower, utility-scale solar, wind, nuclear, bioenergy, and geothermal, as well as energy ownership. Footnoted wiki pages accompany all power facilities included in the GIPT, updated biannually. For more information on the data collection process that underpins GEM’s power sector trackers, please refer to the Global Integrated Power Tracker methodology page.

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

James Norman

Research Analyst

james.norman@globalenergymonitor.org

The post Despite a record year, India needs to double renewables deployment by 2030 to meet energy targets appeared first on Global Energy Monitor.

Chinaʼs continued coal power expansion is undermining the countryʼs clean energy progress, according to a new report from the Centre for Research on Energy and Clean Air and Global Energy Monitor. In 2024, coal power construction activity surged to 94.5 GW, its highest level since 2015, reinforcing coalʼs entrenched role in the power system. Meanwhile, the country approved 66.7 GW of new coal-fired power capacity, with approvals picking up in the second half after a slower start to the year.

While China is leading the world in renewable energy deployment—adding a record 356 GW of wind and solar capacity in 2024—the simultaneous expansion of coal power raises critical concerns about its ability to transition away from fossil fuels. Instead of replacing coal, clean energy is being layered on top of an existing fossil-fuel-heavy system, making it increasingly difficult to achieve the intended shift toward a renewables-driven power sector.

Despite the slow-down in previous years and early 2024, the coal power permit rebound in the second half of 2024, was not insignificant and contradicts policy commitments to curb coal consumption. The uptick in coal power permits threatens to lock in fossil fuel reliance at a time when Chinaʼs power system needs greater flexibility to integrate renewables.

In 2024, more than 75% of newly approved coal power capacity was backed by coal mining companies or energy groups with coal operations, reinforcing coalʼs dominance even when market fundamentals do not justify expansion. Long-term coal power contracts, as well as local government justifications for new plants – often based on economic growth rather than grid reliability – and the strong influence of coal mining companies in financing new projects are further delaying the energy transition.

Competition between coal and renewables is intensifying, with growing curtailment of wind and solar generation, particularly in the fourth quarter of 2024.

These trends challenge Chinaʼs climate commitments, including the targets set out by President Xi Jinping personally to “strictly control coal-fired power generation projects, and strictly limit the increase in coal consumption over the 14th Five-Year Plan period and phase it down in the 15th Five-Year Plan period”. The report warns that without urgent policy shifts, China risks reinforcing a pattern of energy addition rather than transition, limiting the full potential of its clean energy boom.

Qi Qin, China Analyst at CREA: “China’s rapid expansion of renewable energy has the potential to reshape its power system, but this opportunity is being undermined by the simultaneous large-scale expansion of coal power. The continued approval and construction of new coal plants—often driven by industry interests and outdated contracts rather than actual grid needs—risks locking China into fossil fuel dependence at a time when flexibility is crucial for integrating clean energy. Without decisive policy shifts, Chinaʼs energy transition will remain an ‘energy addition’ rather than a true transformation away from coal.”

Chinese coal power and mining companies are sponsoring and building new coal plants beyond what is needed to back up the countryʼs impressive growth in solar and wind power. The continued pursuit of coal is crowding out the countryʼs use of lower-cost clean energy, and is threatening to undermine President Xiʼs 2021 pledge to strictly limit coal consumption and phase it down over the next five years.

Christine Shearer, Research Analyst at Global Energy Monitor

The post When coal won’t step aside: The challenge of scaling clean energy in China appeared first on Global Energy Monitor.

Key Takeways

• Prospective utility-scale solar and wind capacity — projects that have been announced or are in the pre-construction and construction phases — grew by over 20% globally in 2024 from 3.6 terawatts (TW) to 4.4 TW, only half of what is needed for global tripling renewable goals.
• Outside of China and the Group of 7 (G7) rich nations, only half of solar and wind projects designated to come online in 2024 were actually completed on time. 
• Global operating capacity increased by 14% in 2024, as at least 240 gigawatts (GW) of utility-scale solar and wind came online.
• Despite their 45% share of global gross domestic product (GDP), G7 countries are building only 10% of planned solar and wind projects.

Prospective solar and wind capacity grew by over 20% in 2024

During 2024, prospective solar and wind capacity grew by over 20% from 3.6 terawatts (TW) to 4.4 TW¹, according to new data from Global Energy Monitor (GEM). GEM’s Global Solar Power Tracker and Global Wind Power Tracker include all projects that have been announced, entered pre-construction, or are currently under construction for solar capacity over 1 megawatts (MW) and utility-scale wind capacity over 10 MW. Utility-scale solar and wind are largely equal in their prospective development, with 2 TW and 2.5 TW respectively. However, solar photovoltaic (PV) is anticipated to account for 80% of global renewable energy capacity growth until 2030, due to the expanding distributed solar market and the construction of new large-scale projects.

Despite the surge in prospective capacity, even if the entirety of the 4.5 TW were to become operational by 2030, GEM finds that it would still not be enough to reach the goal of tripling renewables capacity by 2030 set at COP28, which requires roughly 9 TW of wind and solar to be built. Moreover, the construction rates of solar and wind outside of China remain low, with only 7% of prospective capacity (226 gigawatts (GW)) currently under construction, jeopardizing the pace and scale necessary for renewables implementation.

Figure 1

China has the largest prospective capacity for both utility-scale solar and wind, with over 1.3 TW. Over one-third of these planned projects (36%) are already under construction, compared to the global average elsewhere of 7%. Meanwhile, India, with the world’s fifth-largest GDP and 30% of projects in construction, targets adding nearly 130 GW of prospective utility-scale solar and wind capacity in the upcoming years, and 35 GW of these additions will be connected to the grid by March 2025.

Figure 2

On-time solar and wind project completion rates lag

Historically, not all planned projects become operational on time. Existing limitations in the physical grid, permitting bottlenecks, and lack of financial mechanisms are often reasons for low completion rates. GEM data included 185 GW of solar and wind farms that were under construction as of December 2023 and designated to become operational before the end of 2024. Globally, only 59% of these projects started producing electricity on time.

Figure 3

A disparity exists in completion rates across G7 countries,² China, and the rest of the world. About 76% of solar and wind projects in G7 countries became operational within the originally planned time frame. This figure declines to 55% in China and further drops to 52% in other non-G7 countries. Moreover, 10% of the projects in other non-G7 countries were shelved in 2024 instead of becoming operational, whereas, this number is negligible in G7 countries and China. This means that only half the planned solar and wind capacity came online on time outside China and the G7, while one-tenth of this capacity was suspended.

Although the permitting procedures for solar and wind farms differ in some countries, it is safe to assume projects under construction already secured land rights, permits, and grid interconnection pre-approvals before the beginning of construction. This highlights the significance of mobilizing public and private investments in developing economies to complete planned renewable projects on time.

Correspondingly, the final days of COP29 were dominated by global climate finance discussions. Countries were encouraged to submit more ambitious, investable, and equitable nationally determined contributions (NDCs) to transition away from fossil fuels in energy systems. Most of these and other discussions in the international arena focus on total operating and planned capacity, while low project completion rates, and potential reasons behind them, are overlooked.

At least 240 GW of utility-scale solar and wind capacity became operational in 2024

The February 2025 release of the Global Solar Power Tracker and the Global Wind Power Tracker shows at least 240 GW of utility-scale solar and wind became operational in 2024.³ This is a lower figure than the International Energy Agency’s earlier forecast (378 GW), as it does not include projects for which the start year is unknown.

China has the largest operating capacity for utility-scale solar and wind. GEM has tracked at least 891 GW of operating utility-scale solar and wind capacity in China. China officially installed 277 GW of utility and distributed solar and 80 GW of wind in 2024, and GEM has tracked 136 GW of those utility-scale solar and wind installations to the asset level.

In the first seven months of 2024, solar and wind in the United States produced more energy than coal, a first for the country. By the end of 2024, the United States had 274 GW of operating solar and wind capacity. India has added at least 10 GW of new solar capacity annually since 2021 and has an operating capacity of solar and wind above 109 GW, as of December 2024.

Figure 4

The wealthiest nations aren’t building their fair share of solar and wind projects

China is not only leading the world in operating projects but it also plans to build more than two-thirds (70%) of all utility-scale solar and wind projects in the coming years. Comparing the share of global GDP and under-construction projects for G7, China, and the rest of the world illustrates an asymmetry for utility-scale solar and wind projects. G7 countries own about 45% of global GDP but only plan to build 10% of global solar and wind projects. From another perspective, G7 countries have half the world’s wealth and are constructing the same amount of wind and solar power — about 59 GW — as the countries that make up the bottom quarter of GDP.

Figure 5

Political barriers and implementation disincentives could further reduce G7 countries’ contribution to renewables in the upcoming years. In January 2025, the Trump administration issued an executive action to suspend new offshore wind leasing, which would halt about 5 GW offshore wind projects currently under construction. However, the International Renewable Energy Agency has called for G7 countries to increase their solar and wind targets to comply with the 1.5°C pathway targets.

It should be noted that in addition to having financial resources to invest in solar and wind energy, resource potential for solar and wind and other technical factors are considered when locating these facilities. From an energy democratization and just energy transition viewpoint, planning for a larger share of global renewables to be built in developing countries is favorable. 

However, non-G7 countries, excluding China, are set to build only one-fifth of the global solar and wind projects in the upcoming years.

About The Global Solar And Wind Trackers

The Global Solar Power Tracker is a worldwide dataset of utility-scale solar photovoltaic (PV) and solar thermal facilities. It covers all operating solar farm phases with capacities of 1 megawatt (MW) or more and all announced, pre-construction, construction, and shelved projects with capacities greater than 20 MW. The Global Wind Power Tracker is a worldwide dataset of utility-scale, on- and offshore wind facilities. It includes wind farm phases with capacities of 10 megawatts (MW) or more.

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.

GEM data serves as a vital international reference point that is being used by agencies including: Intergovernmental Panel on Climate Change, International Energy Agency, United Nations Environment Programme, U.S. Treasury Department and the World Bank. Furthermore, industry data providers such as Bloomberg Terminals and the Economist and academic institutions like University of Oxford and Harvard University draw on this data.

Media Contact

Diren Kocakuşak

Research Analyst

diren.kocakusak@globalenergymonitor.org

The post Wind and solar year in review 2024 appeared first on Global Energy Monitor.

• 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

The post Europe Gas Tracker 2025: Hydrogen edition appeared first on Global Energy Monitor.

In all, proposed coal plants in the OECD region have decreased from 142 in 2015 to just five today – a drop of 96%. 

This is according to Global Energy Monitor’s latest Global Coal Plant Tracker (GCPT) results, completed in the third quarter (Q3) of 2024. The GCPT catalogues all coal-fired power units 30 megawatts (MW) or larger biannually, with the first survey dating back to 2014.

Figure 1

The OECD is an intergovernmental organization with 38 member countries founded in 1961 to stimulate economic growth and global trade, comprising many of the wealthiest countries on the globe.

Of the thirteen OECD countries with coal plant proposals in 2015, all but Türkiye have since pledged to stop building new coal plants. 

There are exceptions to the pledges for coal plants that significantly lessen or “abate” carbon dioxide emissions through the use of carbon capture and storage (CCS) technology. Four of the five remaining proposals include plans for CCS.

The drop in proposals puts the region well on its way to “no new coal,” defined as cancelling all unabated coal proposals not under construction.

The OECD and no new coal

Since 2015, proposed coal-fired capacity in the OECD has fallen from 142 coal proposals totaling 111 gigawatts (GW) to five proposals totaling 3 GW. 

None of the five proposals have the necessary permits for construction, meaning it will likely be several years before construction begins – if they are built at all, as most of the proposals since 2015 in the OECD have been abandoned entirely. 

Of the 111 GW proposed in 2015, 82% (91 GW) have since been shelved or cancelled, compared to 17% (19 GW) commissioned. The remaining 1% (1 GW) has been under construction since 2019, the last time a coal plant has broken ground in the OECD. 

The 111 GW of proposals in 2015 were located across thirteen countries: Australia, Canada, Colombia, Germany, Greece, Israel, Italy, Japan, Poland, South Korea, Türkiye, UK, and the U.S.

Since 2015, twelve of the thirteen countries have pledged support for no new coal, whether as part of the international Powering Past Coal Alliance or through a domestic moratorium on new coal plant permits. The UK phased out coal power entirely this year.

“No new coal” commitments have been aided by the decreasing costs of competitive power sources, including gas and, increasingly, solar and wind power. Additionally, many countries have seen sustained opposition campaigns to new coal over pollution and high energy costs.

As the OECD turns away from new coal, coal power capacity in the region peaked in 2010 at 655 GW and has since declined by about one-third to 443 GW as countries shut down aging coal plants.

Figure 2

Türkiye resists no new coal

To date, the government of Türkiye has resisted calls for no new coal, despite repeated rollbacks in its coal plans.

Most of the country’s proposed coal plants have not materialized. Since 2015, over 70 GW of planned coal plant capacity in Türkiye has been called off compared to 6 GW commissioned, translating to a cancellation rate of 92% since 2015 – one of the highest cancellation rates in the world.

Figure 3

Coal plant proposals in Türkiye face a myriad of challenges, including strong public opposition over coal plant pollution and coal industry privatization, and domestic lignite coal that is low-quality and unreliable, leading many plants to use higher-cost imported coal instead.

In Q3 2024, the licenses for two coal plants – Karaburun and Kirazlıdere – were canceled due to irregularities in the environmental permitting process and the loss of interest in the investment by the plant sponsors. Another plant, Malkara, was shelved due to a lack of activity.

The developments have left Türkiye with one coal plant proposal – a remarkable development after being among the top ten countries with proposed coal-powered capacity for nearly a decade.

Despite the setbacks, Türkiye has not committed to ending new coal plant proposals. Its recently updated climate pledge, submitted during COP29, makes no mention of coal phaseout.

The country’s remaining proposal is a 688 MW two-unit expansion of the sizable Afşin-Elbistan power station complex in the city of Kahramanmaraş. Local residents have opposed the project, saying the increase in pollution in the densely-populated city will lead to thousands of premature deaths and cost billions of dollars.

Australia, Japan, the U.S. and “clean coal” 

The remaining four coal plant proposals in the OECD are located in Australia, Japan, and the U.S. 

While the governments of all three countries have recently pledged support for “no new coal”, they also support CCS to lessen or “abate” emissions from coal plants.

Abated coal plants are considered compatible with no new coal pledges if they meet Paris agreement-aligned definitions regarding “substantially lower” carbon emissions. 

Critics argue CCS proposals are more expensive and polluting than cleaner electricity alternatives, often relying heavily on government subsidies in order to be economically viable. Only a handful of CCS coal plants have reached commercial operation, and none have achieved their target carbon capture rate. 

The Japanese government signed on to a G7 agreement earlier this year to phase out unabated coal power by the mid-2030s and continues to promote a suite of “clean coal” technologies both domestically and abroad. The country’s proposal is a new coal gasification unit at J-Power’s Matsushima power station, dubbed GENESIS. The proposal is a veritable hodgepodge of “clean coal” tech, with plans to co-fire biomass, ammonia, and hydrogen, as well as utilize CCS. 

The U.S. under President Biden also signed on to the G7 agreement and was one of twelve countries that joined the Powering Past Coal Alliance during COP28 in 2023. The country has two Department of Energy (DOE)-backed proposals with plans for CCS, as required under pending regulations for new coal power plants. While the future of both the coal pledges and regulations are uncertain given the recent re-election of Trump, to date the former president has been unable to turn the tide for coal, with more coal power capacity retired under Trump’s first term than either Obama or Biden, and no new coal plant built in a decade. 

Australia’s Labor party, voted into power in 2022, recently joined a COP29 call for no new unabated coal. The country has not commissioned a new coal plant since 2012, with over 13 GW proposed coal-fired capacity cancelled since 2010. The country’s remaining coal proposal, the Collinsville (Shine Energy) power station, has been touted by its sponsors as a “high efficiency, low emissions” (HELE) coal project with plans to include CCS.

About the Global Coal Plant Tracker

The Global Coal Plant Tracker provides information on coal-fired power units from around the world generating 30 megawatts and above. The GCPT catalogues every operating coal-fired generating unit, every new unit proposed since 2010, and every unit retired since 2000.

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

Christine Shearer

Project Manager, Global Coal Plant Tracker

christine.shearer@globalenergymonitor.com

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