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.

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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.

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Sarah Lerman-Sinkoff

Research Analyst, Methane

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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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The post BRICS can lead clean energy transition in new members, where fossil fuels predominate appeared first on Global Energy Monitor.

• 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.

For just five of the top companies owning oil- and gas-fired power plants, GEM found 10.7 million tonnes of hidden CO2 emissions for 2022. The social cost of this much carbon is $2 billion in climate costs per year, or $43 billion of the remaining lifetime climate cost of all hidden gas plants. 

In the case of Saudi Electricity Company, these hidden carbon emissions amount to US$1.3 billion in climate costs per year and nearly $33 billion over the lifetime of these fossil fuel power plants. 

This lifetime climate cost is comparable to a third of the social cost of Hurricane Katrina, half the cost of Australian wildfires from 2019, or a third of the cost of India’s deadly heat waves in 2021. GEM’s ownership tracker, in tandem with Climate TRACE’s emissions data, provides insights into the “hidden”¹ emissions from gas plant assets that companies fail to include in their annual sustainability reports.

Most of the companies’ “hidden” emissions are due to certain plants falling outside a company’s selected reporting boundaries. Three of the five companies disclosed emissions only for plants they operate, despite the fact that they are beneficial owners² of several other active power plants.

Analysis through GEM’s Global Energy Ownership Tracker enables a deeper look to find “hidden” emissions on a company level. The following section describes different ways companies can hide emissions, and the final section details exactly what the “hidden” emissions are of the five companies investigated.

For an in-depth look at how companies hide emissions, see the following background on the Greenhouse Gas Protocol.

How companies hide emissions

The Greenhouse Gas Protocol (GHG Protocol) is the most common carbon emissions accounting method used by corporations. It defines which types of emissions to include in a company’s greenhouse gas (GHG) accounting and how to calculate them. While thoughtfully developed, the protocol has accounting loopholes that companies use to avoid disclosing emissions from assets that they are beneficial owners of.

The GHG accounting protocol is undergoing a revision process for a new release in 2025. The protocol staff noted that multiple carbon accountants have provided feedback that the voluntary choice of accounting approach is too ambiguous and needs to be rectified.

Categorizing emissions: The three Scopes

The GHG Protocol sets forward three classifications, called Scopes, for how to categorize a company’s greenhouse gas emissions based on where emissions originate.

Scope 1: Direct emissions from sources a company owns or controls, like fuel burned in company vehicles or on-site emissions from industrial processes. 

Scope 2: Indirect emissions from purchased energy, such as electricity, steam, or heating, used in a company’s facilities. 

Scope 3: All other indirect emissions across a company’s value chain, including raw material production, transportation, waste disposal, employee commuting, and product usage by customers.

Scopes 1 and 2 are typically seen as emissions within a company’s control. They are “deemed to be material to investors” under an SEC ruling in March 2024 on climate-related disclosures. Scope 3 emissions are more challenging for a company to influence and change, since they originate across a company’s value chain.

Boundaries are unclear for which emissions should fall into Scope 3 versus Scopes 1 or 2. The following section describes how companies decide what falls under their controlled (Scope 1 and 2) emissions.

Defining which emissions fall under a company’s control

For calculating which emissions should be included in annual climate reports, the GHG Protocol provides companies a choice of three different approaches: the operational control approach, financial control approach, and equity share approach. 

Operational control approach: Companies account for emissions from assets for which they have operational control. This includes joint ventures where the company makes management and board-level decisions.

Financial control approach: The company accounts for emissions from operations under its financial control (as defined consistent with international financial accounting standards).

Equity share approach: The company accounts for all emissions from assets the company owns. The emissions attributed to the company are the total emissions of the asset multiplied by the company’s percent equity share. (e.g. A company that owns 40% of a gas plant would include 40% of the plant’s total emissions in its emissions report.) 

In addition to hiding emissions by selecting advantageous accounting approaches, some companies also set extra boundaries in their emissions reporting. The selection of additional boundaries is a reflection of the company’s decisions and doesn’t relate to recommendations from the GHG Protocol. For example, a company may only disclose emissions from select subsidiaries or from entities that exist in certain jurisdictions.

Why do companies hide emissions?

As investors move to adopting climate risk assessments as part of their due diligence, companies are being pushed to properly disclose their risks and opportunities in the context of climate change. This can be seen in both the SEC’s March 2024 ruling on climate-related disclosure and the European Union’s Corporate Sustainability Due Diligence Directive (CSDDD). A lower emissions footprint may make the company look more financially desirable.

In addition, certain jurisdictions, such as California, have begun implementing laws requiring corporations to disclose their Scope 1 and 2 emissions. Non-compliance with reporting mandates leads to financial penalties. Some jurisdictions set carbon limits and fine companies in excess of the limit.

At the same time, companies want to look ethical to their consumers. As consumers express concerns about corporate impacts on worsening climate change, it is in corporate interest to look as “green” as possible to consumer bases.

Below is an in-depth look at each company’s portfolio and a description of its incomplete emissions accounting.

World’s largest owners of oil and gas power plans and the costs of their hidden emissions

Saudi Electricity Company

Saudi Electricity Company set its reporting boundary as “all its entities within the Kingdom of Saudi Arabia, where Saudi Electricity has ‘operational control’ in accordance with the Greenhouse Gas (GHG) Protocol.” Its boundaries also include the following subsidiaries: The Saudi Energy Production Company, National Grid SA, Dawiyat Telecom Company, Saudi Electricity Company for Projects Development, Dawiyat Integrated Company for Telecommunications and Information Technology, and Solutions Valley Company.

Saudi Electricity Company owns three plants — Shuqaiq 2 Independent Water and Power Project, Qurayyah CC power plant, and Rabigh 2 IPP power station — through companies excluded from Saudi Electricity’s chosen reporting boundary of the six subsidiaries specified above.

Egyptian Electricity Holding Company

Egyptian Electricity Holding does not explicitly state which emissions accounting method it uses in its annual report, but it does disclose a list of all power plants included in its emissions estimates. Of the 37 power plants owned by the company according to GEM’s Global Energy Ownership Tracker, 31 were disclosed by the company.

The six undisclosed gas plants⁴ are 100% owned by Egyptian Electricity Holding, and it is unclear why they were omitted from the report.

Calpine Corporation

Calpine’s Sustainability Data report suggests that they take an operational control accounting method approach.

Two⁵ of the twelve plants found in the Climate TRACE dataset are not under the company’s operational control and would therefore have been excluded from emissions reporting.

Chubu Electric Power Co. Inc.

Chubu Electric Power uses the equity method of emissions accounting for its consolidated subsidiaries and affiliates in the integrated annual report. The company does disclose Scope 1, 2, and certain categories of Scope 3 emissions. However, the company does not include its investments in the emissions calculations. The boundaries used for the company’s calculations include “Chubu Electric Power, Chubu Electric Power Grid, and Chubu Electric Power Miraiz; the three businesses of nuclear power generation, renewable energy and power transmission and transformation.” 

JERA Co Inc, a joint venture owned 50% by Chubu Electric Power Co. Inc., is also included in Chubu’s emissions calculations, although Chubu does not clarify which scope is used to account for JERA’s emissions.

Of the 32 gas plants that are jointly or partially owned by Chubu Electric Power according to GEM’s data, 27 are included in the company’s disclosed emissions. Chubu discloses emissions for 26 of these gas plants through its 50% ownership in JERA Co Inc. Chubu does not disclose emissions for the remaining five gas plants,⁶ in which Chubu has 20% or less ownership. These plants are not disclosed, because they fall within subsidiaries outside the company’s chosen boundary and Chubu has less than 20% ownership in each. 

Current accounting does not require reporting entities with less than 20% ownership. The assumption here is that 20% or less values are small amounts of carbon, and that excluding them reduces the time and resources companies need to put into carbon accounting. However, GEM’s Ownership Tracker solves this problem for energy and heavy industry companies.

Entergy Corporation

Entergy published both a full climate report and a separate in-depth GHG inventory. The inventory discloses the list of 29 combustion plants included in its reported emissions. GEM identified one additional combustion plant owned by Entergy, the Louisiana 1 Power Station, that is excluded from Entergy’s calculated emissions, because it exists “for the sole use of Exxon under a long-term lease agreement.” Even though Entergy’s GHG inventory claims the company does not have operational control, it has a 100% ownership stake in four of the five units of this plant and would account for these emissions if it chose a financial control accounting approach.

However, U.S. Energy Information Administration (EIA) data show that unit 5 of the Louisiana 1 Power station is owned by ExxonMobil, and that Entergy is the operator of all units in the Louisiana 1 Power Station. The EIA data are in conflict with the footnote in the Entergy GHG inventory, so GEM chose to rely on EIA data. If Entergy does operate the Louisiana 1 Power station, then the plant emissions should be attributed to itself under the accounting standards it chose. Therefore, GEM has attributed the emissions to Entergy in this article until proven otherwise.

¹ Hidden emissions are not comprehensive; they only represent the emissions sources that Climate TRACE tracked in 2022. It is technically possible that each company has other “hidden” emissions not uncovered in this report.

² A beneficial owner is an entity or person who benefits from the ability to significantly influence a company’s decisions, receive profits and dividends from the business even if not the legal owner, and potentially exercise control over the direction of the company’s operations. Companies should disclose assets they benefit from in their emissions disclosures.

³ These emissions were calculated using the EIA’s 2022 Carbon Dioxide Emissions at Electric Power Plants dataset.

⁴ Assiut Mobile power plant, Mallawi Mobile power plant, West Assiut Mobile power plant, Gerga Mobile power plant, Bani Ghalib Mobile power plant, and Samalut Mobile power plant

⁵ Whitby cogeneration station and Greenfield Energy Centre

⁶ Enecogen power station, Ras Laffan B power plant, Ras Laffan C power plant, Merwedekanaal power station, and Lage Weide 6 power station

What is the Global Energy Ownership Tracker?

The Global Energy Ownership Tracker (GEOT) provides information on the chain of ownership for various energy projects. The dataset maps each level of the chain from the direct owner up to their highest-level parent, such as corporations, investment firms, and governments. 

Ownership links are reported with the percentage of ownership, including owners that have controlling interest as well as those with minority, non-controlling interests.

This asset ownership data set covers five of GEM’s trackers: coal-fired power plants, oil- and gas-fired plants, coal mines, steel plants and bioenergy, and will soon include data on oil and gas pipelines and heavy industry sectors like cement and iron ore mining.

What is Global Energy Monitor?

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

Media Contact

Anna Mowat

Project Manager, Global Energy Ownership Tracker

anna.mowat@globalenergymonitor.org

The post World’s largest oil and gas plant owners hide billions of dollars in climate costs appeared first on Global Energy Monitor.

The COP29 climate change conference falls at a critical time, as countries evaluate their pledges to climate action before submitting revised ambitions in respective Nationally Determined Contributions — or NDCs — next year. Stimulating collective ambition requires leadership, precisely what COP29 host Azerbaijan has yet to deliver in its own plans. The host nation’s approach is modest, at best, with wind and solar projects in development only expected to bring about a 10% increase in renewables share of capacity by 2027 and no plans for further projects beyond that date. Global Energy Monitor’s Global Integrated Power Tracker data indicate similarly low levels of progress against unambitious targets across the region, with a 13 GW deficit in targeted renewable capacity additions among Caucasus and Central Asia (CCA) countries. At the same time, the fossil-powered buildout continues apace, with more than three times as much fossil capacity under construction in the CCA region than from wind and utility-scale solar. Course correction is essential to uphold the collective pledges on energy made at COP28.

Key Findings

• Power projects in development fall short of meeting the renewable energy targets of countries in the Caucasus and Central Asia (CCA) region. Six CCA countries detail targets in the 2030–2040 range for renewable capacity additions — including wind, solar, and hydropower — adding up to 43 GW (Turkmenistan and Kyrgyzstan lack specific targets). However, GEM data show 30 GW of renewable capacity in development across these same six CCA countries, a 13 GW deficit. Georgia and Tajikistan’s targets rely on large hydropower projects, which, aside from associated environmental and financial sustainability concerns, may offer a limited contribution in the 2030 time frame due to long construction lead times.
• COP29 host Azerbaijan shows no in-development wind or utility-scale solar projects beyond those due for completion by 2027, implying capacity additions are just sufficient for achieving the country’s stated target of a 30% renewable share of capacity by 2030 — roughly a 2 GW addition. Recent announcements from the Azeri Government suggest a rollout of wind and solar capacity by 2030 of up to 8 GW. However, the lack of further renewables projects in the project pipeline calls into question the integrity of the energy transition in Azerbaijan. Furthermore, the 30% target, first announced five years ago, only represents a ~10% increase over legacy hydropower capacity, and suggests limited ambition in the current renewables target.
• All eight countries in the CCA region are developing additional coal or oil and gas plant capacity. Oil and gas plant capacity leads the buildout, with 24 GW of capacity in development, half of which is under construction. By comparison, new coal plant capacity is getting built at a far lesser rate, with only two small coal units currently under construction in Kazakhstan, due to replace existing units up for retirement. However, the risk of further coal plant expansion remains, with nearly 8 GW capacity in development across four CCA countries.
• More than three times as much fossil capacity is under construction in the CCA region than from wind and utility-scale solar. Total capacity under construction from wind and utility-scale solar in CCA countries totals 3.5 GW, less than a third of the figure for projects fueled by coal, oil, or gas. An additional 4.8 GW of hydropower capacity is also under construction but mostly comprises two large projects that won’t contribute to power generation before 2030.

Introduction

After back-to-back gatherings in the Middle East, the annual United Nations Climate Change Conference or Conference of the Parties (COP) moves to Baku, Azerbaijan, marking the first time the event has been hosted by a country in the Caucasus and Central Asia (CCA) region.

The Azerbaijani presidency faces the tall task of building on the achievements of COP28, namely the “UAE Consensus” that calls on countries to transition away from fossil fuels. Chief amongst a long list of priorities are agreeing on a new post-2025 finance goal, developing ambitious updated Nationally Determined Contributions (NDCs), and operationalizing the provisions of the Global Goal on Adaptation and carbon markets under Article 6 of the Paris Agreement.

However, Azerbaijan’s hosting of COP29 has attracted criticism, increasingly referred to as an authoritarian petrostate, with concerns over the strength and integrity of the country’s role in shaping and progressing the conference agenda. Any mention of transitioning away from fossil fuels was absent in President-Designate Mukhtar Babayev’s “action agenda” of priority initiatives to be brought to the table in Baku in November, and an independent assessment has found the country’s climate actions “critically insufficient.” The country’s active development of new oil and gas fields and allegations of a renewed crackdown on media and civil society activism add to the concerns over the host’s legitimacy.

However, Azerbaijan is not the first and won’t be the last fossil fuel-producing country to take center stage in climate diplomacy. The door has not yet closed on the COP29 host to demonstrate climate leadership, with one of its strongest available actions to submit an early and ambitious updated NDC. Such “bar-raising” actions could help push other countries into higher levels of commitment, particularly amongst neighboring countries where fossil fuel extraction is still a cornerstone industry. As a powerful platform to promote a regional focus and encourage involvement and support, Azerbaijan’s COP29 presidency can raise international awareness for the Central Asia and Caucasus region and its possibilities for a clean energy transition.

Spanning three countries in the South Caucasus — Azerbaijan, Armenia, Georgia — and five countries in Central Asia — Kazakhstan, Tajikistan, Uzbekistan, Turkmenistan, and the Kyrgyz Republic (Kyrgyzstan hereafter) — the CCA region’s national governments have made strides in recent years with the introduction of carbon neutrality plans, and the geography harbors significant potential for solar, wind, and hydropower. Yet, investments still favor development plans for coal and oil and gas, and the challenges to energy transition in the region are manifest: aging Soviet-era transmission infrastructure, winter energy crises, energy security concerns, regional trade constraints, and a lack of domestic financial resources for investment.

As global attention turns to this year’s marquee climate change event, this report seeks to interrogate the status of power sector transition in the CCA region and highlight the distance still to go in phasing out fossil fuels. The report’s analysis draws upon GEM’s trackers for coal, gas, oil, hydropower, utility-scale solar, wind, nuclear, bioenergy, and geothermal, housed within the Global Integrated Power Tracker (GIPT). For a detailed analysis of each CCA country, see the dedicated country profile sections (Azerbaijan, Armenia, Georgia, Kazakhstan, Tajikistan, Uzbekistan, Turkmenistan, and Kyrgyzstan) in the downloadable PDF version of the report. See dedicated summary tables for summaries of GEM’s power sector data for CCA countries.

I. The CCA power sector is largely old and fossil-fueled, with underutilized wind and solar potential

The power sector development in CCA countries reflects the region’s endowments of coal, oil, gas, and hydropower resources. The region’s operating oil and gas plants tend towards the south and west of the CCA region, concentrating around major gas fields in Uzbekistan (Kashkadarya and Fergana Valley), Turkmenistan (Amu Darya basin), and Azerbaijan (Shah Deniz and Umid). Oil and gas plants constitute the majority of total power capacity in Uzbekistan, Turkmenistan, Azerbaijan, and Armenia.

Four CCA countries operate coal plants, but only Kazakhstan relies heavily on this source, which makes up around 57% of the country’s total operating capacity and 80% of the region’s total operating coal capacity. Operating coal plants co-locate with major coal mines towards the northeast, particularly in the Palovdar region, host to the Ekibastuz coal basin and Kazakhstan’s largest coal mine, Bogatyr.

Three CCA countries have a majority share of hydropower in their respective power mixes, and all but Turkmenistan have operating hydropower facilities. These hydropower facilities cluster towards the mountainous south and east, particularly in Tajikistan and Kyrgyzstan, where hydropower is the primary power source. The Caucasus mountains also host numerous hydropower facilities, which Georgia relies on most heavily, accounting for nearly three-quarters of its power mix.

Operating power facilities across the CCA region are relatively old, with GEM data showing an average age amongst coal, gas, and hydropower plants of 40 years, double the global average. Azerbaijan and Turkmenistan have comparatively younger power plants. Still, upgrades were required at the countries’ oldest and largest power plants, the Azerbaijan thermal power plant and the Mary power station. In addition to lower efficiency, older power sector assets are prone to equipment failure, prompting increased supply interruptions and accidents in recent years. As many thermal power plants in the eastern CCA countries are combined heat and power plants (CHPs), which also provide heating to the residential sector, plant failures leave some residents without heat during the region’s harsh winters. Furthermore, the region’s power grid faces a similar situation and suffers above-average network losses from worn-out or poorly maintained infrastructure.

The region’s predominantly state-owned national energy companies often lack incentives for investments, and regulated energy tariffs typically don’t reflect the cost of production, further indebting producers. Increasing power demand across the region, averaging 3% per annum over the last decade, compounds the issues faced by the underperforming power system. Despite many CCA countries’ positions as major fossil energy producers, several have resorted to electricity imports in recent years to cover deficits, particularly in winter. A similar situation also occurs in the hydropower-dominated power systems of the CCA region, where aging infrastructure contends with seasonal water shortages and climate-affected water availability.

Despite the numerous challenges facing power sector development amongst CCA countries, the region also holds great potential for cleaner forms of electricity generation. Notably, the technical potential for wind and solar power is vast within the region, particularly in the lowlands and plains of Central Asia. This potential is not only constrained to the region’s largest countries. Azerbaijan has a technical potential for 157 GW of offshore wind and 23 GW of solar capacity.

Additionally, several power sector developments point toward a nascent movement for energy sector transition in the region. For instance, Kazakhstan pioneered renewables targets with accompanying support mechanisms amongst CCA countries, evolving to a competitive process in subsequent years that saw the first online auction for renewables projects in 2018. The country currently hosts more than double the combined operating wind and solar capacity of all other CCA countries. Uzbekistan is following suit, introducing competitive bidding processes to attract foreign investment in large-scale solar projects, and was the leading recipient in the region four years in a row for funding from the European Bank of Reconstruction and Development. Furthermore, several initiatives target enhanced regional electricity integration, notably efforts for Tajikistan and Turkmenistan to reconnect their national power systems to the Central Asian Power System (CAPS).

Despite these steps in the right direction and the great potential of wind and solar power in the region, fossil capacity additions remain the mainstay of power system development amongst CCA countries.

II. All CCA countries have fossil-fueled power capacity in development

All eight countries in the CCA region have either coal or oil or gas plants at one of three “in development” stages tracked by GEM data — projects that have been “announced” or are in the “pre-construction” and “construction” phases. In-development oil and gas plants are more prevalent than coal, with all but Tajikistan currently considering new oil and gas capacity. Four CCA countries are planning new coal capacity, but only Kazakhstan has new units under construction.

With 24 GW capacity in development, oil and gas outnumbers the same figure for coal (7.9 GW) by three to one. Nearly half of the total figure for in-development oil and gas capacity is made up of projects under construction (11.8 GW). This contrasts with in-development coal projects, where just two new units, totaling 195 MW, are under construction, according to GEM data.

Although most CCA countries are pursuing new oil and gas plants, only Azerbaijan, Kazakhstan, Turkmenistan, and Uzbekistan have oil and gas capacity under construction. Already the most gas-heavy countries in the region, the proposed oil and gas plants will radically augment existing capacity if built. For instance, in-development plants in Kazakhstan would triple existing operational oil and gas capacity. In Uzbekistan, if 10 GW of in-development oil and gas capacity is built, the country’s operating oil and gas plant fleet would reach 24 GW, double the figure for any other CCA country.

Outside of these four countries, oil and gas projects in development also have the potential to significantly expand capacity in less gas-heavy power mixes. For example, in Georgia, the planned expansion of the Gardabani Combined Cycle power station would increase the current gas plant fleet by more than half. Kyrgyzstan currently has no operating oil or gas plant capacity but is actively pursuing over 1,600 MW of new oil and gas capacity over three separate project locations, equivalent to 40% of the total power capacity in the country.According to GEM data, planned retirements of currently operating oil and gas plants are limited. Only three oil and gas units detail potential plans for decommissioning: a 60 MW unit at the Atyrau CHP power station in Kazakhstan and two 300 MW units at the Syrdarya power station in Uzbekistan, all in 2024. Thus, net oil and gas capacity additions in the CCA region prevail. GEM data show over 70% of in-development oil and gas capacity in the CCA region slated for operation by 2027. If built, the oil and gas capacity coming online by that year would constitute a 50% increase in the existing operating capacity of oil and gas plants in the CCA region.

Four CCA countries are planning new coal projects, totalling 7.9 GW of capacity in development. However, GEM data show a far smaller proportion of this in-development coal figure in the construction phase compared to oil and gas plants, some 195 MW, or less than 3%. The under-construction coal capacity will replace two existing units at coal plants in Kazakhstan, a 130 MW unit at the Karaganda State Regional power station-2, and a 65 MW unit at the Ust-Kamenogorsk TETS power station. Kazakhstan also leads the CCA region for pre-construction and announced coal projects, totalling 4.6 GW, with over half the proposed capacity located in Ekibastuz, a major coal mining center in northeastern Kazakhstan.

Outside of Kazakhstan, the new coal capacity in Kyrgyzstan, Tajikistan, and Uzbekistan comprises announced projects only, totalling 3 GW. Kyrgyzstan accounts for 1,860 MW of this announced capacity across two projects: the 660 MW Jalal-Abad power station, with Russian contractor AB Energo as the proposed contractor, and the 600 MW Kara-Keche power station, for which the Kyrgyz Ministry of Energy and China National Electric Engineering have a memorandum on construction. The future of announced coal plants in Tajikistan and Uzbekistan appears less assured. If built, the Fon-Yagnob power station would more than double Tajikistan’s operating coal fleet. However, the current development status of the project remains unknown. And while the announced 300-600 MW expansion at the Angren power station in Uzbekistan appeared to have attracted China Railway and PowerChina as investment partners, development updates were not forthcoming in 2024.

As well as new coal capacity in development, GEM data show 1,686 MW of operating coal-fired capacity in the CCA region with a planned retirement date. Most of this capacity is due to come offline by 2027 and is associated with units at four plants: three in Kazakhstan (two at Almaty, plus the Zhezkazgan power station), and the Bishkek power station in Kyrgyzstan. Depending on whether in-development coal projects are realized, these planned retirements could see a net reduction in the total CCA operating coal fleet in the coming years. However, most coal units scheduled for retirement at these three plants are designated for conversion to gas-firing or replacement with gas plant technologies of equal or greater capacity.

III. Non fossil-fueled capacity in development is 50% greater than the figure for coal and oil and gas projects but is being built at half the rate

Looking beyond prospective coal and oil and gas projects, capacity in development across CCA countries appears to favor non-fossil sources. GEM data show in-development wind, utility-scale solar, nuclear, and hydropower projects in the CCA region totalling 48.3 GW capacity, about 50% greater than the equivalent figure for coal and oil and gas projects (31.9 GW).

However, only 17% of non-fossil power projects are in the construction phase compared to 34% for coal and oil and gas projects. Furthermore, over half of the 8 GW non-fossil capacity in construction is accounted for by two large hydropower projects — the Rogun plant in Tajikistan and the Kambarata-1 plant in Kyrgyzstan. Two of the Rogun hydroelectric plant’s six 600 MW units are now operational, but full commissioning is not expected until 2033. At the 1,860 MW Kambarata-1 plant, construction of the power facility itself won’t commence until 2025, with full commissioning a further nine years off. Although the two projects are major components of a drive to increase generation and improve domestic and regional energy security, long construction times won’t see their contribution before 2030. Furthermore, the projects face the added challenge of managing the region’s shared water resources, which sees upstream Kyrgyzstan and Tajikistan replenish reservoirs in summer while downstream Uzbekistan and Kazakhstan depend on that same water during the main growing season.

GEM data show Armenia, Kazakhstan, and Uzbekistan with plans for new nuclear power facilities. Still, the majority of this new capacity is at the announced stage. The Armenian government is considering plans for additional nuclear capacity and is reviewing options for a 1,200 MW plant and smaller modular units but has yet to identify a favored supplier. On October 6, 2024, Kazakhstan conducted a national referendum on the proposed 2.4 GW Ulken nuclear power plant, with 71% of those who cast ballots voting in favor, despite public opposition, reported irregularities at the polls, and silencing critics and activists. Announced plans for the 2.4 GW Navoi nuclear power plant in Uzbekistan appear to have halted. Instead, a new 330 MW six-unit small modular reactor (SMR) nuclear power plant is in development in the Jizzakh region of Uzbekistan, with a targeted commissioning year of 2028. However, the Uzbek Energy Minister commented in a recent interview that the new nuclear plant is still at the design phase. So, as with hydropower projects, new nuclear plants are, at best, medium-to-long-term options for increasing generation.

Beyond these long lead-time hydropower and nuclear projects, construction phase projects for non-fossil power sources are extremely limited in the CCA region. GEM data show Uzbekistan making up virtually all wind and utility-scale solar projects under construction in the CCA region (a single project in Armenia — the 55 MW Masrik solar farm — is the only other). Under construction wind and solar capacity in Uzbekistan comprises two large 500 MW wind farms and nine solar farms, averaging 270 MW, totaling 2,447 MW. However, this is still less than the 5,848 MW oil and gas capacity under construction in the country (even when taking into account 600 MW due for decommissioning at the Syrdarya power station).

Capacity additions from small-scale facilities below the threshold GEM data covers could make important non-fossil contributions to the power mix in the CCA region. However, per-country research (see country profile sections below) suggests this small-scale segment has yet to make significant inroads in most CCA countries. For example, most CCA countries with hydropower resources are planning small-scale hydropower facilities. Yet, these additions are generally piecemeal and won’t offer sufficient capacity to supplant dominant power sources. Planned small-scale hydropower additions of significant size were only identified for Uzbekistan (438 MW) and Armenia (380 MW).

The situation is comparable for distributed solar, where stated plans and support measures are rarely detailed and appear to be a missed opportunity amongst the CAA countries. However, the region holds examples of successful scale-up of distributed solar PV, again from Uzbekistan and Armenia. With support from a feed-in tariff, 35,000 residential households in Uzbekistan currently host 150 MW rooftop solar PV. In Armenia, distributed solar PV capacity stood at 354 MW as of September 2024, up from 18 MW five years previously, providing 9% of national electricity generation in H1 2024.

Despite these examples of a distributed approach, wind and solar capacity in development across the CCA region generally favors larger, utility-scale projects. GEM data show that the majority of these in-development wind and solar projects are implemented or owned by firms based in the Middle East or China, notably the Saudi firm ACWA Power, Masdar of the United Arab Emirates, and several Chinese utility companies (e.g., China Gezhouba Group Co.). It will be important to monitor the development of this ownership pattern for new wind and solar capacity in the CCA region, to ensure the scalability and long-term financial sustainability of the capacity additions.

Owner-operators based in the Middle East and China account for 80% of wind and utility-scale solar capacity in development in the CCA region

IV. Wind, utility-scale solar, and hydropower capacity in development falls short of renewable energy targets in most CCA countries

All CCA countries have submitted updates to their first nationally determined contributions (NDCs) under the Paris Agreement, pledging varying degrees of climate actions contingent on the level of international support received. CCA countries have also adopted various energy strategies aligned with their international climate commitments, typically framed within respective national development plans (see accompanying GEM Wiki page for a compilation of climate pledges and energy sector targets).

Comparing GIPT tracker data for power projects in development with capacity targets detailed within these energy strategies reveals the distance between ambition and reality. Six CCA countries detail targets for renewable capacity additions in the 2030–2040 range — including wind, solar and hydropower — adding up to 43 GW (Turkmenistan and Kyrgyzstan lack specific renewables targets). However, GEM power tracker data show 30 GW renewable capacity in development across these same six CCA countries, a 13 GW deficit. An assessment of each CCA country shows some cases where capacity in development exceeds stated renewable targets. Yet, these cases are due to reliance on large hydropower projects or due to unambitious targets.

Azerbaijan appears to be an example of the latter. The COP29 host has been keen to highlight how plans for 2 GW of additional renewables capacity will see the country exceed a 30% renewable share of total electricity capacity by 2030. GEM data suggest wind and utility-scale solar PV projects coming online by 2027 will fulfill nearly all of the 2 GW quota. Around 1,000 MW comes from projects implemented by Abu Dhabi Future Energy Company (better known as Masdar), in collaboration with SOCAR, the State Oil Company of Azerbaijan, including the Bilasuvar (445 MW) and Neftchala (315 MW) solar plants, as well as the Absheron-Garadagh wind farm (240 MW). Saudi energy group ACWA leads the Area 1 / Khizi 3 wind farm (240 MW), with an additional 200 MW wind project in discussion, while three additional solar projects account for a further 440 MW.

However, GEM data show no further renewable projects in development in Azerbaijan, calling into question the certainty of capacity increase beyond the 2 GW additions. Recent public statements by the Energy Ministry have indicated plans to commission 7 to 8 GW of additional renewable capacity by 2030, with a pipeline of candidate renewable projects totalling 28 GW. Although the 2 GW of wind and solar additions in development mark a significant increase from a low base, the actual generation that the new farms produce would be unlikely to match that of new gas capacity under construction, specifically, the 1,280 MW Mingecevir gas power station, due for commissioning by the end of 2024.

Neighboring countries of Armenia and Georgia both target high renewable shares in electricity generation: Georgia 85% by 2030 and Armenia 50% by 2040, helped by existing large hydropower facilities. However, GEM data suggest renewables projects in development in Armenia falling short of the targeted capacity increases, particularly for wind, with no known projects tracked. Compared to stated targets, the apparent excess of renewable capacity in Georgia is due to nearly 2 GW of hydropower projects in development. Aside from the long construction lead times of large hydropower projects, several of the proposed projects face public opposition due to associated environmental and social disruption, notably the 700 MW Khudoni Hydro Power Plant. GEM data for in-development wind and utility-scale solar in Georgia total only one-third of the targeted increase.

A similar diagnosis can be made for hydropower-dominated Tajikistan and Kyrgyzstan, where total capacity in development favors new hydropower. The available information on in-development hydropower in Tajikistan does not indicate how many of these projects would become operational in time to contribute to the country’s target of 1,500 MW renewable addition by 2030. Kyrgyzstan’s National Development Strategy from 2018 references a 10% share in the total energy mix from renewables (excluding large hydropower) but lacks any indication of the breakdown between sources or the necessary capacity additions. However, GEM data suggest that Kyrgyzstan has the most renewable capacity in development as a proportion of operating capacity. Although three-quarters of this 9,700 MW in-development total is for hydropower projects, the 2,480 MW of wind and utility-solar projects would constitute a substantial addition if built.

Despite Kazakhstan’s pipeline of coal and oil and gas projects (the largest in the CCA region), a presidential decree issued in June 2024 includes targets for increasing the non-fossil share of electricity generation to 15% by 2030, rising to 50% by 2050. The Government’s Power Sector Development Plan to 2035, from earlier in the year, includes targets of 9,000 MW wind, 500 MW solar, and 2,660 MW hydropower. However, GEM data from power projects in development are well below these figures, with no renewables projects in the construction phase.

In early 2024, the Senate of Uzbekistan voted to increase renewable energy targets to 27 GW by 2030 and the share of renewable power generation to 40% (including hydropower). GEM data show that Uzbekistan has the largest absolute volume of renewable capacity in development in the CCA region and the most capacity under construction. However, the total figure for wind, utility-scale solar, and hydropower projects in development still falls 30% short of the target, at 19.2 GW.

Turkmenistan’s NDC details one of the least ambitious targets in the CCA region, and its reference to an intensity-based target is unlikely to bring about absolute reductions in emissions. Neither the Turkmen NDC nor the National Strategy of Turkmenistan on Climate Change details specific targets for renewables. This tallies with GEM data showing no renewables in development.

Appendices

Summary data tables for CCA countries, by source and development status. Construction projects include those where site preparation and equipment installation are underway. Pre-construction projects are those that are actively moving forward in seeking governmental approvals, land rights, or financing. Announced projects include those described in corporate or government plans or media releases but have not yet taken concrete steps such as applying for permits. Retired projects describe those decommissioned or dismantled; this term is also used if the plant has been destroyed by war.

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.

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Renewables to eclipse fossil fuels for half of the world’s population

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Fossil capacity is set to drop below half of the power capacity mix in the BRICS bloc for the first time ever this year, signaling an important milestone in the clean energy transition for countries that still host the vast majority of the world’s coal power.

Data for this report comes from GEM’s Global Integrated Power Tracker (GIPT), an online multi-sector dataset of power stations and facilities worldwide. The tracker provides unit-level information on thermal power (coal, oil, gas, nuclear, geothermal, bioenergy) and renewables (solar, wind, hydro). The tracker includes data on unit capacity, status, ownership, fuel type, start year, retirement date, geolocation, and more.

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Brazil, Russia, India and China founded the “BRICS” group of emerging economies in 2009, and expanded membership to South Africa in 2010, and earlier this year to the United Arab Emirates, Ethiopia, and Egypt. These countries play a major role in energy and climate diplomacy and together represent 46% of the world population, 38% of GDP, and 48% of carbon dioxide emissions.

Key Findings

• The share of power capacity in the BRICS group fueled by coal, oil, and gas could fall below 50% by the end of this year. The fossil dominance of power capacity in the BRICS has fallen in recent years and is currently close to 50%. The crossover for the bloc is imminent, as non-fossil capacity additions to mid-year already outnumber coal, oil, and gas plant projects slated for commissioning in 2024. While most BRICS countries show a declining trend in their fossil share, China leads the group, with its fossil-fueled capacity share falling twice the amount of other BRICS countries over the last five years.
• Wind and utility-scale solar capacity in development outnumber power projects fueled by coal, oil, and gas by two to one in the BRICS. These two technologies, together with distributed solar PV, which GEM data do not cover, are set to contribute the greatest non-fossil capacity additions in the BRICS. Although this vast pipeline is significantly buoyed by China, wind and utility-scale capacity in development also outnumbers the figure for fossil-fueled power projects in five other BRICS members.
• Despite fossil-fueled power capacity losing ground in the BRICS’ power mix, virtually all members are building additional coal, oil, or gas plants. GEM data shows all BRICS group countries, save Ethiopia, with fossil-fueled power projects in development. If built, in-development fossil-fueled projects would increase operating coal and oil/gas capacity in the BRICS groups by 36% and 53%, respectively.
• BRICS countries have enough renewables projects in development to nearly triple capacity by 2030. Although the BRICS group has no collective endorsement of the global goal of tripling renewables capacity by 2030, China’s recent record wind and solar capacity additions and several members’ ambitious clean energy plans put a three times scale-up within reach. If the 326 GW of wind and utility-scale solar capacity additions in 2023 continued to 2030, the BRICS group would see total renewable capacity increase by more than 2.5 times. Furthermore, the sum of the BRICS’ in-development renewables projects due for completion by 2030 is 2,276 GW or around 95% of the additional utility-scale renewable capacity estimated as necessary to achieve the global tripling target.

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The groups’ growing role in energy and climate diplomacy within and beyond the bloc is underscored by several host nation roles for the annual UN climate summit and G20 presidency. At the same time, additional invitees to the bloc, including Saudi Arabia, present the possibility for BRICS to merge the interests of leading oil and gas producers (Saudi Arabia, UAE, Russia, Iran) with those of leading coal producers (China, India, Russia, South Africa), in effect creating a new force on the international diplomatic stage with deeply vested interests in continued fossil production.

With close to half the world’s electrical power capacity and nearly half of its fossil-fueled capacity, the power sector represents the blocs’ greatest source of energy-related CO2 emissions. Power demand growth in the BRICS has averaged 5% per year in the last decade, roughly double the global average. Ahead of the annual BRICS summit in Kazan, Russia, in October 2024, this report seeks to provide a timely summary of the state of power sector transition in the nine BRICS countries. The report’s analysis draws upon GEM’s trackers for coal, gas, oil, hydropower, utility-scale solar, wind, nuclear, bioenergy, and geothermal, housed within the Global Integrated Power Tracker (GIPT). For a detailed analysis of each BRICS nation, see dedicated country profile sections: Brazil, Russia, India, China, South Africa, Egypt, Ethiopia, Iran, and the United Arab Emirates (available in the downloadable PDF). See dedicated summary tables for summaries of GEM’s power sector data for BRICS countries.

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BRICS countries make up half of the world’s power capacity

Existing power capacity across all technologies in BRICS group countries totals 4.2 terawatts (TW), or just under half of the global total (9.0 TW). The capacity mix across the bloc is diverse, spanning all eight power sectors covered by GEM trackers, including the two fossil sources in coal and oil and gas, as well as six non-fossil sources, including solar, wind, hydropower, nuclear, bioenergy, and geothermal. Despite the diverse sourcing of electricity across the BRICS, each member relies heavily on a single source.

The dominant source in six BRICS group countries is fossil-powered, underscoring the importance of phasing out incumbent power sources for energy transition.

With over 70% of BRICS total power capacity, it’s hard to understate the significance of China within the bloc. China’s heavy reliance on coal, together with sizable shares in India, South Africa and Russia, see the BRICS countries accounting for an outsized share of the global coal fleet, some 70% of global operating coal capacity. Amongst the top ten coal producers globally, these four BRICS countries account for 99% of operating coal capacity across the bloc, some 1,469 GW. Coal has the largest share of total power capacity in three of these countries: China 41%, India 51% and South Africa 70%.

Oil and gas plants are less prominent across the group, making up 22% of the global total oil/gas plant capacity. However, this technology is an important power source for certain members, constituting the majority of operating power capacity in four BRICS countries: Russia 47%, Egypt 89%, Iran 84%, and United Arab Emirates 77%. Together these four countries account for 60% of operating oil and gas plant capacity across the BRICS group and are all amongst the top ten oil and gas producers globally. While oil and gas plants feature less prominently in the overall capacity mix of China (5% of total), the total installed capacity is the greatest amongst the BRICS (145 GW).

Hydropower is the dominant power source in Brazil and Ethiopia, accounting for 49% and 87% of total capacity, respectively. The relative abundance of rainfall in western Ethiopia coincides with the highland terrain, which creates considerable hydropower potential for conventional storage technologies. Brazil’s much larger hydropower base likewise capitalizes on abundant rainfall and favorable geography, with run-of-river technologies also used on high-flow-rate rivers (notably the Madeira, São Francisco, and Paraná). China, India, and Russia also have sizable hydropower sectors, though the share of the power mix in each country is more modest, at between 10 and 20%.

Although the BRICS group of nations also host sizable operating fleets of other power technologies, none reach the shares of dominant power sources. For example, Brazil has the most bioenergy power capacity of any country in the world outside of China, but the share of total installed capacity is less than 10%. China is building nearly half of the world’s new nuclear power plants and will overtake France within the next few years to hold the world’s second-largest nuclear fleet. Yet, nuclear power would still struggle to reach a double-digit share of China’s total installed power capacity.

The urgent task of phasing out dominant fossil sources from the power mix is even more stark when accounting for the generally lower capacity factors of leading renewable technologies such as wind and solar. China is a case in point, where the total installed capacity of wind and solar capacity now equals that of coal capacity. Yet, coal generation in China is over four times greater¹ than that of wind and solar combined.

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BRICS’ wind and utility-scale solar capacity in development is double coal, oil, and gas

Across the BRICS group, in-development wind and utility-scale solar projects — those that have been announced or are in the pre-construction and construction phases — total 1,550 GW, or roughly double the figure for fossil-fueled capacity, and half of the total in-development capacity across all technologies. Adding in-development hydropower to the wind and utility solar figure sees the capacity for in-development fossil-fueled projects in the BRICS outnumbered by nearly three to one.

Across BRICS group countries, utility-scale solar is the leading technology for capacity in development, with 814 GW. Over 99% of this capacity comprises solar photovoltaic (PV) technologies (as opposed to solar thermal), and 70% is located in China. Naturally, the larger solar market in China corresponds with a greater proportion of the in-development figure for utility-scale solar. However, Brazil and Egypt also host sizable pipelines of in-development utility-scale solar capacity, which are ten times the level of existing operating capacity in each county.

Wind follows utility-scale solar closely with 744 GW of capacity in development across the bloc, 67% of which is located in China. Offshore wind technologies make up 27% of the in-development figure, with 67% of this segment located in Brazil and 31% in China. This strong showing for Brazil, with more in-development offshore wind capacity than any other country globally, reflects the country’s vast coastline, ample wind resources, and shallow nearshore — however, uncertainty surrounding the regulatory framework for offshore wind risks stalling the buildout.

Hydropower also shows a large volume of in-development projects, some 708 GW, of which 66% is pumped storage. China and India make up 94% of in-development hydropower capacity and 99% of the pumped-storage segment. Both China and India increasingly require options for energy storage to facilitate the integration of massive wind and solar additions and ensure grid stability.

China and India together make up 82% of nuclear power plant projects in development. China alone has 118 GW of capacity in development stages, which puts the country not only first worldwide for this metric, but also surpasses the second through eighth place countries combined.

Plans for new bioenergy plants are limited compared to other technologies, with almost all in-development capacity within China and Brazil (92%). These two countries rank first and third for installed bioenergy capacity globally in 2023. Bioenergy plants in China are powered mainly by municipal waste and agricultural residues. Brazil’s primary bioenergy fuel for power is bagasse — the biomass that remains from the crushing of sugarcane — for which Brazil is the world’s largest producer.

Only Ethiopia is pursuing plans for new geothermal plants, with 550 MW capacity in development. Currently, the country has a single, now defunct, geothermal plant. Still, it aspires to mirror the success of neighboring Kenya, which has tapped the Eastern African Rift for over 900 MW of geothermal capacity.

The considerable pipeline of non-fossil power projects is a positive sign and, if built, will help erode the existing fossil majority used for electricity generation. However, the amount of fossil capacity in development within the BRICS is still vast in scale, with global ramifications for the energy transition.

For coal, China and India alone account for 86% of the global in-development number and 98% within the BRICS. For oil and gas power projects, BRICS’ share of the global in-development number is lower, at one-third. However, all BRICS countries other than Ethiopia and India have capacity in development. If built, in-development fossil-fueled projects would increase operating coal and oil/gas capacity in the BRICS groups by 36% and 53%, respectively.

Ultimately, the size of the in-development tranche for each technology and the proportion reaching the construction phase will determine which technology wins out.

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BRICS’ non-fossil fueled capacity under construction exceeds that of coal, oil, and gas

All BRICS countries are building fossil-fueled power capacity, with 287 GW capacity currently in the construction phase across the group. However, the non-fossil-fueled capacity under construction is more than double this figure, at 629 GW. For comparison, the ratio of non fossil to fossil capacity under construction in both the G7 and EU is three to one. A weighting towards non-fossil capacity additions has also been observed historically in the BRICS group, with the share of fossil-powered technologies in total power capacity falling from a peak value of around 70% in 2007 to 50% last year.² Should all power projects in the BRICS group get built, the fossil-powered share would drop below 50% for the first time.

This crossover may take place this year. GEM data show 72 GW of fossil capacity in the BRICS group slated for commissioning in 2024 and a further 88 GW without a known target start date, totalling 158 GW. However, non-fossil capacity additions to mid-2024 already exceed this amount, totalling 190 GW in China, India, and Brazil alone.³ As year-end capacity statistics are collected, it is likely that the non-fossil share becomes the majority. For comparison, the European Union reached 50% non-fossil share at the start of the 2010s, and the G7 hit parity last year.

Within the bloc, the balance between fossil and non-fossil capacity varies. However, the fossil component rarely shows signs of increasing. In hydropower-dominated Brazil and Ethiopia, robust wind and solar PV growth over the past decade has pushed Brazil’s non-fossil share close to 90%, while no known coal, oil, or gas prospects in Ethiopia will maintain the near 100% non-fossil powered electricity system.

China’s non-fossil contribution to the power capacity mix surpassed 50% in 2023, with massive wind and solar additions propelling this share 20 percentage points in a little over five years. Despite the unrivaled volume of fossil-powered projects under construction in China, there are hints of an impending slowdown in coal capacity additions. The country drastically reduced approvals for new coal power in the first half of 2024, granting permission to only twelve projects totaling 9.1 GW, equivalent to just 8% of the permitted amount in all of 2023. However, this slowdown in permitting may take time to work through the pipeline, and construction activities remain robust due to the substantial arrears of new coal capacity permitted in previous years. Nevertheless, accelerating non-fossil capacity additions, particularly from wind and solar, will continue to edge out coal’s share.

South Africa and Egypt complete this set of five BRICS countries building more non-fossil capacity than fossil. However, the absolute amount of non-fossil capacity under construction is modest compared to the total installed capacity, and the additions would change little of the current dominance of fossil power in these two countries.

GEM data for India, Iran, Russia, and the United Arab Emirates all see fossil-powered capacity in construction exceeding non-fossil. However, factoring in distributed solar PV additions in India, which GEM data does not cover, would likely see the non-fossil segment prevail in this country. This non-fossil surplus would help keep coal’s share of total power capacity below 50% (a threshold passed mid 2024 for the first time since the 1960s). However, it may not be sufficient to realize the Indian Government’s target of a 50% share of non-fossil capacity in the power mix by 2030, particularly given the recent spree of coal permitting.

In Russia and the UAE, coal, oil, and gas plants planning retirement within the next 2–3 years would tip the balance in favor of non-fossil capacity additions. While net capacity additions would alter little of Russia’s current two-thirds share of fossil fuels in the power mix, a faster pace of change is occurring in the UAE. In little over half a decade, the UAE has gone from close to zero to around a 25% non-fossil share of capacity, propelled in large part by the phased commissioning of all four units at the Barakah nuclear power plant and completion of several multi-gigawatt solar plants, including Al Dhafra solar farm, the world’s largest single-phase installation. Only Iran remains with a surplus of fossil-powered capacity additions according to GEM’s construction project data, virtually all of which are gas plants using domestically produced fuel supply.

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Total renewable capacity in the BRICS would more than double if annual renewable additions seen in 2023 continued to 2030

The target to triple total global renewables⁴ capacity by 2030, agreed at COP28, is considered the single most important lever for reducing emissions and keeping the 1.5 degree-aligned pathway alive. Despite attracting support from more than 130 countries worldwide to date, the only signatories from the BRICS group are Brazil, Ethiopia, and the UAE. However, before COP28, a similar tripling target expressed in the G20 Leaders’ Declaration, which excluded calls for coal phasedown, did attract support from China and India. China subsequently reiterated its commitment to the tripling goal along with the United States in the “Sunnylands Statement.” Furthermore, the climate and energy plans of India, South Africa, and Egypt all envisage renewable capacity that is close to or exceeding three times the current level. Thus, the role of most BRICS group countries in the global tripling goal is implicit despite no formal support across the bloc.

Getting to triple the level of renewables by 2030 globally — or around 11,000 GW — would require a year-on-year growth rate of around 16%, with annual additions rising from around 600 GW in 2024 to 1,500 GW in 2030. Assuming the same 16% growth rate for the BRICS group countries over this period, total renewable installations would reach 5,430 GW in 2030, with annual additions increasing from 308 GW in 2024 to 749 GW in 2030. Although global tripling does not imply all countries increase renewables three-fold, this level of scale-up is consistent with analyses from the IEA, Climate Analytics, and the University of California, Berkeley, which all show 2030 renewables capacity in major BRICS group countries of three to three-and-a-half times 2022 levels.

Record capacity additions saw the BRICS’ renewables fleet grow by 331 GW in 2023. This level of annual capacity additions is similar to the amount consistent with tripling for the coming years, estimated at 308 GW in 2024 and 357 GW in 2025 for BRICS group countries. Most of the recent capacity additions in BRICS group countries are from wind and solar PV technologies, making up 98% of the 2023 capacity additions or 326 GW. If annual wind and solar additions were to continue at this rate for the next seven years out to 2030, the BRICS’ renewables fleet would grow to 4,200 GW of installed capacity, or 77% of the tripling value for the bloc.

GEM data tracks 2,276 GW of renewable capacity in development across BRICS group countries. This in-development figure is over 60% of the additional renewable capacity required between 2024 and 2030, consistent with tripling renewables (3,510 GW).⁵ As GEM data do not cover the distributed solar PV segment of renewable capacity, the 2,276 GW of BRICS renewable capacity in development likely accounts for a larger share of additional renewable capacity required by 2030. Assuming distributed solar PV would cover around one-third of the total additional renewables capacity by 2030, the 2,276 GW of in-development renewables in the BRICS is closer to 95% of the additional capacity required by 2030 for tripling when excluding distributed solar (2,400 GW).

To reach the vast renewable capacity buildout implied in the tripling target, pre-construction and announced projects must be built. Yet, only a quarter of the total in-development figure is currently under construction (572 GW) in the BRICS region. Furthermore, China accounts for an outsized share of this construction tranche, some 90% of the BRICS total. Although the sheer size of the power sector in China implies the country will dominate the share of under-construction projects in the BRICS countries, the country is also building at a higher rate, with 32% of renewable projects in the construction phase compared to 8% among the other BRICS countries. Increasing this construction rate and continually growing the in-development pipeline is vital to all BRICS members contributing to the global goal of tripling renewables.

As all countries start from very different levels of installed renewable capacity, precisely tripling the sum of capacity across all renewable sources may not be desirable or feasible. However, this does not rule out rapid scale-up in other renewable sources. For instance, Brazil would not feasibly triple its 100 GW hydropower base by 2030. However, the country has ambitious plans for non-hydropower renewables, notably the second- and third-largest in-development pipeline globally for solar and wind, respectively. Like- wise, Ethiopia currently sources virtually all electricity from hydropower. Yet, GEM data show in-development wind and hydropower projects double the current installed capacity. By contrast, Russia and Iran have comparatively small amounts of in-development renewable projects, with just 300 MW of wind and solar projects in construction between them. That said, both countries host significant wind and solar resources and ambition for these technologies should far exceed the modest levels of existing installations and in-development projects.

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The BRICS bloc is at a watershed moment. The clean energy transition really is happening everywhere. Still BRICSs are some of the only countries in the world planning new coal projects, which would undermine the impressive progress to date in cleaning up their energy systems.

James Norman, Project Manager for the Global Integrated Power Tracker at Global Energy Monitor

Explore below to find out how much power capacity is in development across BRICs countries, sorted by energy source and project status.

¹Estimated using National Bureau of Statistics of China generation data for the last twelve months.

²Ranges between 49–51%, depending on the capacity data source (IRENA: 50%, Ember: 49%, and 51% when using official government sources).

³Using installed capacity data to July 2024, from respective statistical authorities (China, India and Brazil).

⁴In this section of analysis, “renewables” refers to the same definition used by the IEA, which covers the following technologies: onshore and offshore wind, solar PV and solar thermal, hydropower (including pumped storage), bioenergy, geothermal, and ocean energy.

⁵For comparison, additional renewable capacity required by 2030 in G7 countries is around 1,800 GW. GEM data show 617 GW of renewable capacity in development in the G7 or about 35% of the additional renewable capacity required for tripling.

The post Energy in the BRICS appeared first on Global Energy Monitor.

Key points

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

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

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

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

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

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

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

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

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

The post Mixed messages: New oil and gas extraction areas raise the stakes for methane abatement appeared first on Global Energy Monitor.