The Rise of Community Solar Explained: A Data-Driven Analysis of the New York Market
DG+ Team
August 4, 2021
Owing to supportive policy and lucrative incentives for developers, community solar capacity has seemingly grown exponentially over the previous 5-10 years. In New York State in particular, it now makes up the lion’s share of new distributed generation capacity entering investor-owned utilities’ interconnection queues, or list of generators set to come online in the near future.
However, why have we not seen corresponding growth in on-site solar? After all, there is no shortage of incentives for residential rooftop solar, and rooftop solar capacity undoubtedly furthers the state’s policy goals. Is it merely limitations of the rooftop model, or is there more to the story? The nuances behind New York State’s unprecedented community solar capacity uptake – and its established dominance over the rooftop solar model of distributed generation in the state – deserve a more nuanced look.
The community solar business model: improved access to clean energy
Across many U.S. states, policymakers have pursued rooftop solar incentive programs to help meet ambitious renewable portfolio standards and fight to mitigate the worst effects of rising global temperatures. The obvious value proposition here – apart from offset grid emissions – is that homeowners and businesses get to save significantly on their utility bills.
However, installing solar panels on-site is not possible for all residential and commercial customers. Even after incentives, the upfront cost of on-site solar can reach tens of thousands of dollars for a household, making it financially inaccessible to a large portion of the population. Moreover, the rate of home ownership across the United States stood at just 65.8 percent at the end of 2020 according to the U.S. Census Bureau, meaning that as many as 35 percent of households lack the agency to install rooftop solar in the first place.
Many buildings also face technical issues in terms of either rooftop space, shading from nearby trees or buildings, or low annual “irradiance” (i.e. the amount of useful light energy from the sun that can be converted into electricity). These issues make rooftop solar less feasible for many homeowners and businesses.
Recent policy support for community solar aims to directly address these issues. Sometimes referred to as “community solar gardens” (CSG) or “community distributed generation” (CDG), these solar projects are built similarly to traditional, free-standing utility-scale solar farms. The only difference is that they operate on a much smaller scale.
Instead of selling electricity to a customer via a power purchase agreement (PPA), community solar installations typically interconnect directly to the distribution network and offer subscriptions to local homes and businesses, who in turn receive credits on their utility bill. This makes the benefits of clean, “behind-the-meter” solar electricity significantly more accessible.
Community solar dominates distributed solar uptake in New York
Historical context
New York is already a clear leader in community solar adoption. NY-Sun, the state’s pioneering solar incentive program, has provided robust project revenue streams for developers of distributed solar since 2012.
Key among these is the Value of Distributed Energy Resources (VDER), or “value stack”, approach to compensating distributed electricity generation. Since VDER’s inception in 2017, solar projects have received a level of compensation that is determined by a “stack” of metrics. The stack includes traditional metrics, such as “energy” and “capacity”, but also compensates projects based on their “environmental” and “demand reduction” value. So far, this has resulted in strong project economics for developers of distributed renewable energy in the state. The VDER tariff also includes a specific component for community solar projects – the “Community Adder”.
Despite strong incentives, the extended $111 million budget from 2020 has already been exhausted because of community solar's popularity among developers and subscribers.
From a strong market to exponential growth
In 2016, 227 of 463 megawatts (MW) of distributed solar capacity entering utilities’ interconnection queue pipeline was community solar. This represented 49 percent of all new capacity, a figure that was remarkable at the time because it came only a year after the state’s very first community solar project was approved. However, this was far from the end of the story.
Figure 1: New Solar Capacity Added to Interconnection Queue - Community Solar vs. Customer-Sized - 2016
By 2020, community solar had completely taken over the market for distributed generation across the state. Last year, a whopping 2,128 of 2,329 MW of distributed solar added to the queue was community solar – over 91% of all capacity.
Figure 2: New Solar Capacity Added to Interconnection Queue - Community Solar vs. Customer-Sized - 2020
Indeed, while annual capacity of traditional “behind-the-meter” rooftop and other distributed solar approved in the queue has remained relatively constant, community solar as a share of capacity has ballooned. Community solar now dominates distributed solar in capacity terms, and may even be on its way to rivaling traditional, front-of-the-meter utility scale solar farms.
Of course, it is important to note that interconnection queues are merely a “snapshot” of future generation resources. Projects can take years to develop, and some simply never reach completion. While it is likely that most of this capacity will come online within the next few years, challenges may lie ahead for developers.
A second wave of community solar dominance?
One might think that as incentives run out and the community solar market begins to saturate, the rate of new community solar capacity in the New York interconnection queue would begin to slow. However, exactly the opposite has happened.
In April 2021, utility interconnection queues saw a staggering 378 MW of community solar capacity enter the pipeline, by far the highest monthly figure in the state’s history. Hardly an anomaly, this was followed by another remarkable 370 MW in May 2021. To put these figures into perspective, the nearly 750 MW combined capacity from these two months is equivalent to more than 10 percent of New York’s entire state goal of 6 gigawatts (GW) of installed solar by 2025. It’s worth reinforcing that community solar is a form of distributed generation, as opposed to traditional, megawatt-scale solar farms.
So, why is this happening?
One possible explanation for the dominance of community solar could lie in the nature of how stakeholders perceive these incentives. Community solar is developed similarly to utility-scale solar farms in project finance terms, with monetary credits exchanged for each kilowatt-hour of electricity. Similar to a power purchase agreement (PPA) model, community solar developers monetize the credits by selling subscriptions to households (subscribers).
Renewable energy developers with advanced financial models are far more likely to understand how various incentives can increase returns on their investment in a community solar project, while a home or small business owner is less likely to have the knowledge or resources to determine how such incentives for rooftop panels will increase their long-term savings. There is also a well-known “myopia” among the general public towards clean energy investments with long payback periods, making community solar subscriptions far less risky than installing rooftop panels.
In addition, as community solar developers require customer subscriptions to earn revenue from credits, marketing campaigns are paramount. Because rooftop solar and community solar subscriptions are effectively direct substitutes, increased community solar adoption is a form of market “cannibalization” of on-site rooftop solar. The more households that subscribe to community solar, the fewer rooftops there will be for customer-sited panels.
Another reason could be the state's enhanced focus on environmental justice and equity in the energy transition, recently enshrined in the Community Leadership and Climate Protection Act (CLCPA). Despite the environmental benefits, a common criticism of traditional rooftop solar programs is that they are regressive in nature. If only higher-income households can bear the upfront cost burden of rooftop solar, and thus reap the benefits of distributed generation, low-income households not only miss out on bill savings from solar, but also risk seeing increased tariffs as utilities spread their rate base across increasingly fewer customers – a concept known as the “utility death spiral”.
Community solar, in turn, removes the upfront cost barrier and thus allows low-and-moderate income (LMI) customers, including non-homeowners, to save on their bill by means of distributed generation while largely mitigating the rate base issue. As the CLCPA seeks to ensure that the distributional impacts of the transition to a low-carbon economy do not unfairly fall onto low-income households, it is unsurprising to see the state adopt further policy to support progressive distributed generation business models like community solar. The forthcoming LMI CDG Adder is another example of this trend.
A period of uncertainty
In spite of these positive trends, developers continue to voice their concerns as to whether state support is sufficient for future community solar market growth in New York. While the state has recently announced new, supportive policies, including the above-mentioned LMI CDG Adder, many feel that these are insufficient to take over the vital role that the Community Adder played as a project revenue stream. Evidently, policy support will prove critical to the future direction of the market, and lack of it may not only lead to a stagnation of new capacity entering the pipeline, but also to the development of existing projects being put on hold.
Ironically, the recent 2021 boom may therefore be indicative of a market slowdown. As the CDG Community Adder incentive inched closer to exhaustion in spring 2021, developers were rushing to get their projects into the queue by paying 25 percent of the interconnection cost required to receive the last of the incentive. The unprecedented growth in pipeline capacity in April and May of this year might be a sign of an end to the seemingly unstoppable growth of New York’s community solar industry, rather than future market expansion.
The future of community solar
Like any solution to a complex problem – be it rising global temperatures, energy affordability, or equity in the energy transition – community solar enjoys both strengths and weaknesses. On one hand, community solar lacks the scale of traditional, front-of-the-meter solar farms. On the other hand, it reaches an economy of scale that is far more effective than smaller, more expensive rooftop solar systems. Plus, it solves an equity issue by ensuring that cost savings from the energy transition are also enjoyed by disadvantaged households and renters.
The result is a “middle-ground” approach that, arguably, maximizes the trade-off between efficient grid decarbonization and equitable distribution of the impacts of the energy transition. Time will tell if community solar's time to shine will soon end in New York. In the meantime, many more households will be able to subscribe to a local solar farm.
Owing to supportive policy and lucrative incentives for developers, community solar capacity has seemingly grown exponentially over the previous 5-10 years. In New York State in particular, it now makes up the lion’s share of new distributed generation capacity entering investor-owned utilities’ interconnection queues, or list of generators set to come online in the near future.
However, why have we not seen corresponding growth in on-site solar? After all, there is no shortage of incentives for residential rooftop solar, and rooftop solar capacity undoubtedly furthers the state’s policy goals. Is it merely limitations of the rooftop model, or is there more to the story? The nuances behind New York State’s unprecedented community solar capacity uptake – and its established dominance over the rooftop solar model of distributed generation in the state – deserve a more nuanced look.
The community solar business model: improved access to clean energy
Across many U.S. states, policymakers have pursued rooftop solar incentive programs to help meet ambitious renewable portfolio standards and fight to mitigate the worst effects of rising global temperatures. The obvious value proposition here – apart from offset grid emissions – is that homeowners and businesses get to save significantly on their utility bills.
However, installing solar panels on-site is not possible for all residential and commercial customers. Even after incentives, the upfront cost of on-site solar can reach tens of thousands of dollars for a household, making it financially inaccessible to a large portion of the population. Moreover, the rate of home ownership across the United States stood at just 65.8 percent at the end of 2020 according to the U.S. Census Bureau, meaning that as many as 35 percent of households lack the agency to install rooftop solar in the first place.
Many buildings also face technical issues in terms of either rooftop space, shading from nearby trees or buildings, or low annual “irradiance” (i.e. the amount of useful light energy from the sun that can be converted into electricity). These issues make rooftop solar less feasible for many homeowners and businesses.
Recent policy support for community solar aims to directly address these issues. Sometimes referred to as “community solar gardens” (CSG) or “community distributed generation” (CDG), these solar projects are built similarly to traditional, free-standing utility-scale solar farms. The only difference is that they operate on a much smaller scale.
Instead of selling electricity to a customer via a power purchase agreement (PPA), community solar installations typically interconnect directly to the distribution network and offer subscriptions to local homes and businesses, who in turn receive credits on their utility bill. This makes the benefits of clean, “behind-the-meter” solar electricity significantly more accessible.
Community solar dominates distributed solar uptake in New York
Historical context
New York is already a clear leader in community solar adoption. NY-Sun, the state’s pioneering solar incentive program, has provided robust project revenue streams for developers of distributed solar since 2012.
Key among these is the Value of Distributed Energy Resources (VDER), or “value stack”, approach to compensating distributed electricity generation. Since VDER’s inception in 2017, solar projects have received a level of compensation that is determined by a “stack” of metrics. The stack includes traditional metrics, such as “energy” and “capacity”, but also compensates projects based on their “environmental” and “demand reduction” value. So far, this has resulted in strong project economics for developers of distributed renewable energy in the state. The VDER tariff also includes a specific component for community solar projects – the “Community Adder”.
Despite strong incentives, the extended $111 million budget from 2020 has already been exhausted because of community solar's popularity among developers and subscribers.
From a strong market to exponential growth
In 2016, 227 of 463 megawatts (MW) of distributed solar capacity entering utilities’ interconnection queue pipeline was community solar. This represented 49 percent of all new capacity, a figure that was remarkable at the time because it came only a year after the state’s very first community solar project was approved. However, this was far from the end of the story.
Figure 1: New Solar Capacity Added to Interconnection Queue - Community Solar vs. Customer-Sized - 2016
By 2020, community solar had completely taken over the market for distributed generation across the state. Last year, a whopping 2,128 of 2,329 MW of distributed solar added to the queue was community solar – over 91% of all capacity.
Figure 2: New Solar Capacity Added to Interconnection Queue - Community Solar vs. Customer-Sized - 2020
Indeed, while annual capacity of traditional “behind-the-meter” rooftop and other distributed solar approved in the queue has remained relatively constant, community solar as a share of capacity has ballooned. Community solar now dominates distributed solar in capacity terms, and may even be on its way to rivaling traditional, front-of-the-meter utility scale solar farms.
Of course, it is important to note that interconnection queues are merely a “snapshot” of future generation resources. Projects can take years to develop, and some simply never reach completion. While it is likely that most of this capacity will come online within the next few years, challenges may lie ahead for developers.
A second wave of community solar dominance?
One might think that as incentives run out and the community solar market begins to saturate, the rate of new community solar capacity in the New York interconnection queue would begin to slow. However, exactly the opposite has happened.
In April 2021, utility interconnection queues saw a staggering 378 MW of community solar capacity enter the pipeline, by far the highest monthly figure in the state’s history. Hardly an anomaly, this was followed by another remarkable 370 MW in May 2021. To put these figures into perspective, the nearly 750 MW combined capacity from these two months is equivalent to more than 10 percent of New York’s entire state goal of 6 gigawatts (GW) of installed solar by 2025. It’s worth reinforcing that community solar is a form of distributed generation, as opposed to traditional, megawatt-scale solar farms.
So, why is this happening?
One possible explanation for the dominance of community solar could lie in the nature of how stakeholders perceive these incentives. Community solar is developed similarly to utility-scale solar farms in project finance terms, with monetary credits exchanged for each kilowatt-hour of electricity. Similar to a power purchase agreement (PPA) model, community solar developers monetize the credits by selling subscriptions to households (subscribers).
Renewable energy developers with advanced financial models are far more likely to understand how various incentives can increase returns on their investment in a community solar project, while a home or small business owner is less likely to have the knowledge or resources to determine how such incentives for rooftop panels will increase their long-term savings. There is also a well-known “myopia” among the general public towards clean energy investments with long payback periods, making community solar subscriptions far less risky than installing rooftop panels.
In addition, as community solar developers require customer subscriptions to earn revenue from credits, marketing campaigns are paramount. Because rooftop solar and community solar subscriptions are effectively direct substitutes, increased community solar adoption is a form of market “cannibalization” of on-site rooftop solar. The more households that subscribe to community solar, the fewer rooftops there will be for customer-sited panels.
Another reason could be the state's enhanced focus on environmental justice and equity in the energy transition, recently enshrined in the Community Leadership and Climate Protection Act (CLCPA). Despite the environmental benefits, a common criticism of traditional rooftop solar programs is that they are regressive in nature. If only higher-income households can bear the upfront cost burden of rooftop solar, and thus reap the benefits of distributed generation, low-income households not only miss out on bill savings from solar, but also risk seeing increased tariffs as utilities spread their rate base across increasingly fewer customers – a concept known as the “utility death spiral”.
Community solar, in turn, removes the upfront cost barrier and thus allows low-and-moderate income (LMI) customers, including non-homeowners, to save on their bill by means of distributed generation while largely mitigating the rate base issue. As the CLCPA seeks to ensure that the distributional impacts of the transition to a low-carbon economy do not unfairly fall onto low-income households, it is unsurprising to see the state adopt further policy to support progressive distributed generation business models like community solar. The forthcoming LMI CDG Adder is another example of this trend.
A period of uncertainty
In spite of these positive trends, developers continue to voice their concerns as to whether state support is sufficient for future community solar market growth in New York. While the state has recently announced new, supportive policies, including the above-mentioned LMI CDG Adder, many feel that these are insufficient to take over the vital role that the Community Adder played as a project revenue stream. Evidently, policy support will prove critical to the future direction of the market, and lack of it may not only lead to a stagnation of new capacity entering the pipeline, but also to the development of existing projects being put on hold.
Ironically, the recent 2021 boom may therefore be indicative of a market slowdown. As the CDG Community Adder incentive inched closer to exhaustion in spring 2021, developers were rushing to get their projects into the queue by paying 25 percent of the interconnection cost required to receive the last of the incentive. The unprecedented growth in pipeline capacity in April and May of this year might be a sign of an end to the seemingly unstoppable growth of New York’s community solar industry, rather than future market expansion.
The future of community solar
Like any solution to a complex problem – be it rising global temperatures, energy affordability, or equity in the energy transition – community solar enjoys both strengths and weaknesses. On one hand, community solar lacks the scale of traditional, front-of-the-meter solar farms. On the other hand, it reaches an economy of scale that is far more effective than smaller, more expensive rooftop solar systems. Plus, it solves an equity issue by ensuring that cost savings from the energy transition are also enjoyed by disadvantaged households and renters.
The result is a “middle-ground” approach that, arguably, maximizes the trade-off between efficient grid decarbonization and equitable distribution of the impacts of the energy transition. Time will tell if community solar's time to shine will soon end in New York. In the meantime, many more households will be able to subscribe to a local solar farm.
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Today, 65% of carbon capture, utilization, and storage (CCUS) capacity is used to capture emissions from natural gas processing.
By 2030, hydrogen production, power generation, and heat will be the largest sectoral applications for CCUS.
CCUS is set to grow globally, with North America and Europe poised for particularly rapid growth over the next decade.
The vast majority of the captured carbon will be stored in permanent storage infrastructure by 2030, outpacing carbon use in enhanced oil recovery.
Expected CCUS capacity growth is still not sufficient to meet the IEA’s Net-Zero Emissions Scenario for 2050. Policymakers must enact measures from a wide range of policy and regulatory options available to them to further accelerate CCUS growth.
Overview
Driven by ambitious government emissions-reduction targets, a wide range of decarbonization strategies are underway all around the world, from renewable energy production to transportation electrification. Recently, however, a very different decarbonization approach has started to gain traction: carbon capture, utilization, and storage (CCUS). Instead of replacing a polluting product or process with one that does not produce emissions, CCUS technologies remove carbon dioxide (CO2) emitted from power plants and industrial processes, as well as directly from the atmosphere. The captured carbon can be stored (usually injected deep underground) or used for a wide range of applications, including the manufacturing of construction material, fertilizers, and bioplastics.
Despite its growing popularity, CCUS can be a controversial approach to climate change mitigation. Some opponents argue that developing CCUS technologies gives big emitters like fossil fuel companies a convenient excuse to keep extracting fossil fuels. Some observers also argue that relying too heavily on CCUS, rather than accelerating the use of emissions mitigation technologies, will not help the world meet crucial climate targets.
Despite such skepticism about CCUS, a growing number of governments and firms are deploying CCUS as part of their decarbonization strategies. This is because while the rapid deployment of renewable energy remains the primary strategy for global carbon emission mitigation, even in the most generous of projections, renewables alone will not be enough to meet key climate targets. This is why authoritative projections like those by the Intergovernmental Panel on Climate Change and the International Energy Agency (IEA) also include the use of CCUS technologies.
In this article, we investigate the current state and future projections of the global CCUS landscape: What sectors are employing it, and how is the captured carbon used? How do we expect CCUS deployment to grow in the future? What policies and incentives are necessary for CCUS to reach its potential as a key pillar of a decarbonized society?
To answer these questions, we analyzed the International Energy Agency’s (IEA) CCUS Projects Database. This database covers all CO2 capture, transport, storage, and utilization projects worldwide that have been commissioned since the 1970s and have an announced capacity of more than 100,000 tons per year (or 1,000 tons per year for direct air capture facilities).
Today’s Global CCUS Market
Natural Gas Processing Dominates Global CCUS Applications Today
For the sake of this analysis, “sectoral application” refers to the industry in which CCUS is deployed to capture the emitted carbon before it is stored or transported for use. Broadly speaking, there are eight sectoral applications for CCUS technologies today:
Natural gas processing: CCUS is used to capture carbon emissions from purifying raw natural gas to produce pipeline quality natural gas.
Hydrogen and ammonia production: Hydrogen is a molecule that does not emit carbon when combusted, and has the potential as a clean fuel for the industrial, transport, and power sectors. Ammonia can also be used as a zero-carbon fuel for power generation and a carrier for hydrogen. Yet most hydrogen and ammonia production today uses fossil fuels. CCUS offers a potential solution, as capturing the carbon emitted from hydrogen and ammonia production is a cheaper strategy than using renewable energy to produce these fuels in most regions.
Biofuels: Facilities that produce biofuels like bioethanol, biodiesel, and biogas are also responsible for CO2 emissions, and carbon capture technologies can be used to remove these emissions.
Other fuel transformation: Carbon capture technology is used to sequester emissions from facilities that produce and refine fuels other than natural gas, hydrogen, ammonia and biofuels.
Iron and steel plants: Some industrial processes, notably iron and steel manufacturing, are highly energy intensive and cannot easily be decarbonized. CCUS is one of the most promising emissions reduction methods for these facilities.
Other industry: CCUS is applied to industrial facilities other than iron and steel, such as aluminum smelters, pulp and paper mills, etc.
Power and heat generation: Power and heat generation account for about 30% of primary greenhouse gas emissions globally. Owners of fossil fuel power plants use CCUS to cut those emissions when power and heat are generated.
Directly from the air: Through direct air capture (DAC), CO2 can be removed directly from the atmosphere.
Hover over graph to interact
As the chart above shows, natural gas processing is the dominant of these eight CCUS applications; today, 65% of all CCUS capacity is in the natural gas processing sector. Natural gas processing plants in North America were the earliest adopters of CCUS in the 1970s and 1980s because of the relatively low cost of capturing carbon from these processes and the ability to supply it to local oil producers for oil recovery operations.
Over the last two decades, carbon capture capacity in natural gas processing has increased by 265%, from 8.5 megatons (Mt) of CO2 per year in 2000 to over 31 Mt CO2 per year in 2022. This growth follows the steady increase in natural gas production globally.
Other applications pale in comparison. 7.3 Mt CO2 per year is captured from other fuel transformation processes, 3.5 Mt CO2 from industrial plants other than iron and steel, and 1.6 Mt CO2 from the production of biofuels. The sectors where carbon capture technology will be essential in decarbonization efforts – power generation and heat, as well as iron and steel manufacturing – are still lagging behind at 1.3 and 0.9 Mt CO2 per year, respectively. At 0.004 Mt CO2 per year, DAC capacity is also still in its infancy.
CCUS deployment in sectors other than natural gas processing face a common barrier: the lack of commercial value in capturing CO2. This, combined with the extremely high cost of developing a CCUS project in the absence of substantial and consistent policy support, has made CCUS deployment in industrial applications commercially unattractive. DAC projects are especially costly because the technology is still in its infancy, so there are relatively few companies that develop them.
Policy Support is Scaling CCUS
To address these common barriers, governments have been proactive in passing and implementing measures to encourage the growth of CCUS projects over the past few years. Here, we highlight several of these policy initiatives in North America and Europe.
In the US, the Inflation Reduction Act (IRA) of 2022 offers a considerable boost for CCUS through a tax credit. This tax credit nearly doubles for carbon that is captured from power and industrial plants, and more than triples for CO2 captured from DAC: $60/tonne for utilization from industrial and power sectors, $85/tonne for storing CO2 captured from industrial and power generation facilities in saline geologic formations, $130/tonne for utilization from DAC, and $180/tonne for storage in saline geologic formations from DAC.
This support is coupled with funding under the Infrastructure Investment and Jobs Act (IIJA), which provides approximately $12 billion across the CCUS value chain in the form of R&D funding, loans, and permitting support over the next 5 years. These funding measures by the US government are the most ambitious of any country.
In Canada, the 2022 federal budget included an investment tax credit for CCUS projects that permanently store captured CO2 between 2022 and 2030, valued between 37.5 - 60% of the project cost depending on the type of project. 34 CCUS projects were announced in 2022 and 2023, which will help increase Canada’s CCUS capacity by almost 27 Mt CO2 per year by 2030.
In the European Union, funding programs and regulatory reforms will fuel much of this projected growth, particularly the Connecting Europe Facility - Energy ($6.3 billion between 2021 and 2027) and the Innovation Fund ($41.2 billion between 2020 and 2030) that fund CCUS and other clean energy projects.
Global Oil and Gas Players Lead the Market
While government policies are pivotal for expanding global CCUS capacity, it is companies that ultimately plan, develop, and operate these projects. This section identifies the major players listed in the IEA CCUS Database and highlights the efforts of some of these companies.
The table below shows the ten companies involved in the largest CO2 capture capacities and the core sector in which each company operates.
Company Name
Headquarters Country
Company Sector
Announced Avg. Capacity (Mt CO2/yr)
Equinor
Norway
Oil and gas
134
Fluxys
Belgium
Oil and gas
76
Shell
UK
Oil and gas
62.9
Air Liquide
France
Industrial
51.9
BP
UK
Oil and gas
41.3
Wintershell DEA
Germany
Oil and gas
38
Exxonmobil
USA
Oil and gas
38
Mitsubishi Heavy Industries
Japan
Industrial
27.3
Open Grid Europe (OGE)
Germany
Oil and gas
24.2
Denbury
USA
Oil and gas
21.5
Several patterns can be observed. First is the predominance of oil and gas companies in the CCUS industry. Oil majors including ExxonMobil, Shell, BP, and Equinor are also some of the largest players developing CO2 capture infrastructure. With the recent announcement by ExxonMobil to acquire Denbury to expand its CCUS and enhanced oil recovery (more on this below) capacity, the oil majors in this list are set to consolidate even further. Although not included in the top 10, other US oil companies such as Valero and Chevron are also leading players in this field.
Also notable is the absence of companies that specialize in carbon capture in the top 10. Recently, several firms have garnered attention for their proprietary CCUS technologies, such as CarbFix, CarbonFree, Aker Carbon Capture, and LanzaTech. Yet compared to the multinational energy and manufacturing companies that occupy the top spots in the industry, these pure plays are still small, with total CCUS project capacities of less than 5 Mt CO2 per year each. However, the entry of these specialized companies into the CCUS value chain is encouraging. The IEA notes that the value chain that has historically been dominated by vertically integrated oil and gas companies are starting to break up, allowing new players to innovate and reduce costs in parts of the chain.
To offer deeper insight into the projects in which these companies are involved, we highlight four companies from the table above.
Equinor is a Norwegian oil and gas company whose portfolio also encompasses renewables and other low-carbon solutions. It is the largest provider of pipeline gas to Europe.
Since 1991, Equinor has been a partner in 23 CCUS projects, totalling an average announced capacity of 134 Mt of CO2 per year.
19 of these projects are still in the planning phase, 2 two are operational, 1 one is under construction and one has been decommissioned.
8 of these projects capture carbon from hydrogen/ammonia production processes, 8 others are related to CO2 transport and/or storage, and 3 are applied to natural gas processing.
In 20 of the 23 projects, the captured CO2 is stored permanently.
All but one of these projects are located in Europe (including the UK), with the sole exception of one project being in Algeria.
Shell, a British multinational oil and gas company that was formed in 1907, is vertically integrated and is active in every area of the oil and gas industry.
Shell participates in 28 CCUS projects around the world, with a total capacity of 62.9 Mt of CO2 per year.
23 of these projects are in the planning phase, with the expected operation date ranging from 2024 to 2030.
3 of the projects are already operational, and 2 are under construction.
These projects’ applications vary widely, from 11 projects dedicated to CO2 transport and/or storage, 6 to hydrogen and ammonia production, 3 to natural gas processing, 3 to other fuel transformation, and the rest applied to power and heat, biofuels, and other industries.
In 22 of these projects, the captured CO2 is put into dedicated storage.
Air Liquide is a French multinational supplier of industrial gasses and services to a variety of industries, including medical, chemical, and electronic manufacturers.
It is involved in 29 CCUS projects whose average announced capacity totals 51.9 Mt CO2 per year.
17 of these projects transport the captured CO2, while 6 are in other fuel transformation, 3 are applied to cement manufacturing, 2 are in the iron and steel sectors, and 1 in other industry.
All 29 projects are still in the planning phase, with the expected operation date ranging from 2024 to 2040.
27 of these projects will be located in Europe, and the rest in the US.
Mitsubishi Heavy Industries is an industrial and electrical equipment manufacturer headquartered in Japan, whose wide-ranging portfolio includes aerospace and automotive components, air conditioners, utility vehicles, defense equipment and weapons, and power systems.
Mitsubishi is a partner on 17 CCUS projects, totaling 27.3 Mt CO2 per year in average announced capacity.
All 17 are still in the planning phase and will be located mostly in North America and the UK.
Their sectoral applications will be varied, with 5 projects capturing CO2 from hydrogen/ ammonia production processes, 3 from power and heat, 3 from natural gas processing, 3 dedicated to CO2 transport and storage, 2 from cement manufacturing, and the rest from other industries.
The CO2 captured from 11 of the projects will be permanently stored.
2030 Global Projections
The IEA data includes CCUS projects that have been announced as of March 2023, and whose construction and operation are expected in the future. In this section, we use that data to predict developments in the global CCUS landscape between now and 2030, both in terms of the geographic distribution of growth and the different fates of carbon.
North American and European Policy Will Drive Lead in Regional Capacity Growth
Growing recognition of the role of CCUS technologies in meeting net zero goals is translating into increased policy support all over the world, which in turn is spurring increased growth in CCUS projects. The predominant forms of policy support are tax credits for projects, funding for R&D, and regulatory reforms. Owing to these measures, over 140 new projects were announced globally in 2022, bringing the global announced CCUS capacity up to 45.8 Mt CO2 per year. This compares to 35.7 Mt CO2 per year in 2017, a 28.3% increase over five years.
Looking ahead to 2030, this growth in CCUS capacity is set to accelerate. We can see this trend in the chart below.
Hover over graph to interact
North America will likely account for the vast majority of the increase in CCUS capacity over the next decade, rising roughly 6x from 27.7 Mt CO2 per year in 2023 to 161.8 Mt CO2 per year in 2030. This capacity expansion is in large part due to the region’s established policies designed to stimulate CCUS market growth. Country-specific analysis reveals that the United States will be the primary policy driver of this acceleration, with Canada playing a secondary but important role. With around 80 projects planned for operation by 2030, the CO2 capture capacity in the US is expected to increase by nearly a factor of five, from over 20 Mt CO2 to over 100 Mt CO2 per year, more than 60% of North America’s expected growth.
Although not as drastically as in North America, Europe is also expecting capacity growth, from 2.5 Mt CO2 per year in 2023 to 95 Mt CO2 in 2030 – a nearly 40x increase in less than a decade.
Changes in the Fate of Carbon: High Hopes for Dedicated Storage
Rapid CCUS deployment over the next several years will be accompanied by changes in how the captured carbon is used, known as the “fate of carbon.” As of 2022, most of the captured CO2 was used in enhanced oil recovery (EOR), at 39.9 Mt CO2 per year. EOR is the process of extracting oil from an oil field that has already gone through the primary and secondary stages of oil recovery. In other words, the use of CO2 in EOR is a way to rejuvenate oil production at mature oil fields. This explains the fact that large oil producers have been the leading players developing CCUS capacity and the recent renewed interest from many of those same companies. Although CO2-EOR can produce “carbon negative” oil (depending on a variety of factors), it is often not considered a reliable decarbonization strategy. At the same time, the clear commercial value of additional oil production has driven CO2 use in EOR to be the earliest and primary fate of carbon.
Starting in 2023, this is predicted to change: As shown in the chart below, dedicated storage is set for a take-off as the biggest fate of carbon. By 2030, we expect that 426.5 Mt CO2 per year will be put into dedicated storage infrastructure around the world, which is more than a 38-fold increase over eight years. On the other hand, EOR is projected to experience a more modest 1.7x growth.
Hover over graph to interact
Note: The second fastest growing fate of carbon is labeled “Unknown/Unspecified” because the IEA’s CCUS Database is based on publicly available information, and unfortunately many of the project announcements do not make the fate of carbon clear.
This projected growth in dedicated storage is encouraging. Since more CO2 needs to be sequestered than can be used, much of the captured CO2 needs to be permanently stored. This means that dedicated storage infrastructure is a prerequisite for carbon capture technologies to be deployed.
Many factors, both market- and policy-driven, are propelling the expansion of carbon storage. A growing number of companies, particularly in the manufacturing and energy sectors, are adopting net-zero targets that carve out a role for CCUS. Another factor is the growing proliferation of CCUS “hubs,” or clusters of infrastructure to capture, transport, store and/or use carbon. These hubs help to improve the economics of and therefore facilitate investments in CCUS projects. In the US, a slew of policy incentives, such as the 45Q tax credit passed in 2018 and those in the IRA and IIJA mentioned above, are boosting investments in CCUS projects. In the EU, the revenue from the Emissions Trading System began funding carbon capture, transportation, and storage projects from 2020.
The predicted growth of dedicated permanent storage infrastructure is welcome news from a climate perspective: According to the IEA, getting to net-zero emissions by 2050 requires that 95% of captured CO2 be permanently stored. There is more than enough geologic CO2 storage capacity globally to meet climate goals, and the technology for achieving this – such as pipelines for CO2 transportation, mechanisms for injecting, trapping, and monitoring CO2 underground – is well-established. Since CO2 transport and storage infrastructure needs to be operational before CO2 capture projects are developed, this projection is encouraging.
Barriers Remaining for Future CCUS Growth
More Policy Support is Needed to Boost Private Investment and Innovation in CCUS
Including all announced and planned CCUS projects in the IEA CCUS Database, the global CCUS capacity will reach 265.25 Mt CO2 per year by 2030. How does this projected increase compare to the amount of CO2 that needs to be sequestered to reach the IEA’s net-zero scenario?
Sadly, it falls far short of the target. According to the IEA, to stay aligned with its Net Zero by 2050, CCUS technologies need to capture 1.66 gigatons of CO2 (Gt CO2) per year by 2030 globally, and 7.6 Gt CO2 per year by 2050 to reach net-zero emissions. This means that current and planned capacity of CCUS projects expected in 2030 only accounts for less than 20% of the IEA’s target for 2030. The chart below puts this gap into perspective.
Hover over graph to interact
Given this gap, what more can governments and industry around the world do to rapidly scale up CCUS capacity to meet this target over the next decade? The IEA outlines four high-level priorities:
Creating the conditions that make private investment in CCUS more commercially attractive. Policymakers can achieve this by attaching value on CO2 emissions, providing funding support for capital and operating costs for early projects, and allocating risks across the public and private sectors.
Facilitate the development of CCUS hubs with shared CO2 transport and storage infrastructure. Identifying opportunities for CCUS deployment in specific industrial regions and establishing a business model for carbon transport and storage infrastructure, will go a long way toward this goal.
Identifying CO2 storage. The first step would be to characterize and assess geological CO2 storage around the world. The second is to establish a robust legal and regulatory framework around CO2 storage. Lastly, a concerted campaign to support public awareness will ensure that the general public understands and accepts CO2 storage technology.
Boosting innovation to reduce costs and increase the availability of critical technologies. This can be done through public-private partnerships in R&D and increased funding to revamp innovation in key CCUS applications (especially heavy industry, CO2 use for synthetic fuels, and carbon removal).
The policy support in North America, Europe and elsewhere mentioned above are instances of governments working toward meeting these priorities. But there are additional policy and technological developments that promise to accelerate growth faster than projected in this report.
The US Environmental Protection Agency recently proposed rules that would require power plants to capture or otherwise reduce their carbon emissions. Technological innovations are taking place in chemical absorption systems that can increase CO2 capture rate. The International CCS Knowledge Centre’s feasibility study found that retrofitting existing power plants with CCUS can be cost-competitive, suggesting that the barriers for power plant operators to build retrofit capture facilities may be lower than we assume today. All of these developments point toward the possibility of more rapid CCUS deployment than the IEA dataset projects.
Technologies to capture carbon from the atmosphere or from point sources are integral to the net zero roadmap. The key take-away is that the business case for CCUS is getting stronger each year as policymakers and investors support its development as a necessary climate solution. Yet, much more rapid deployment is necessary if we are to meet emissions targets to stabilize the climate by mid-century. As North America and Europe are set to experience accelerated growth in CCUS capacity, they may act as the catalysts for policymakers and project developers in other regions to also scale up their CCUS capabilities.
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The Rise of Community Solar Explained: A Data-Driven Analysis of the New York Market
At the 28th UN climate change summit held in Dubai (COP28), governments agreed on ambitious new targets to triple global renewable energy capacity and double energy efficiency by 2030. It was also the first time an explicit agreement to “transition away from fossil fuels” was reached.
While the ambitiousness of these agreements should be celebrated, these targets will be very difficult to achieve under current conditions. One of the major barriers will be the continued shortage of finance from developed countries to help low and middle income countries transition away from fossil fuels and scale up cleaner energy sources. Global climate finance increased by approximately 1% of global GDP over the last decade, but it is still too low compared to the levels needed to achieve the low-carbon transition.
Such financing from developed countries will need to take many forms, but one key source is public finance institutions. Public finance institutions are government-backed entities such as development finance institutions (DFIs) such as the China Development Bank and the Japan International Cooperation Agency, and export-credit agencies (ECAs), including the Export-Import Bank of the United States and Export Development Canada that offer subsidized, long-term financing for economic and industrial development.
They play an outsized impact on developing energy capacities around the world, which otherwise struggle to attract private investment because of their high upfront capital cost and high perceived risks. By offering government-backed credit ratings, often at below-market rates and accompanied by large research and technical capacity support, they de-risk large-scale infrastructure financing, “crowd in” private sector finance, and anchor private-public partnerships. The involvement of public finance institutions in the research and development (R&D) and project development phases of a long-term project can help provide certainty over returns on private investment that are otherwise hard to predict or guarantee.
Yet, public finance institutions of many high-income countries still direct most of their investments into fossil fuels. Whether or not public finance is directed will be among the most critical factors that make or break the global energy transition.
In this article, we show the scale of fossil fuel, clean, and other energy investment by public finance institutions in the Group of Twenty (G20) countries, how these investment amounts have changed over time, and which countries receive most of these investments. To do this, we analyzed data from Oil Change International’s Public Finance for Energy Database.
1. Group of Twenty (G20) is an informal intergovernmental forum composed of twenty of the world’s largest economies that meets regularly to coordinate global policy on trade, health, climate, and other issues. Its members are Argentina, Australia, Brazil, Canada, China, France, Germany, India, Indonesia, Italy, South Korea, Japan, Mexico, Russia, Saudi Arabia, South Africa, Turkey, the United Kingdom, the United States, and the European Union. In this article, we exclude the European Union because its public finance is accounted for by its member states (France, Germany, and Italy).
Key Takeaways:
Fossil fuels investments dwarf clean energy: Historically, public finance institutions have invested disproportionately in fossil fuel projects. This reality continues, though to a lesser extent.
China, Japan, South Korea and Canada are the most active fossil fuel funders in the world between 2015 and 2021.
Despite their predominance, fossil fuel investments are on the decline: This is a result of two broad factors: 1) increasing public scrutiny over public finance institutions’ portfolios, and 2) the decreasing demand for coal-fired power plants in developing countries.
The majority of clean energy investments flow to wealthier countries: Even while the relative share of clean energy investments is growing, the global distribution of such investments remains uneven. Investments in clean energy are disproportionately directed at wealthier countries, while most fossil fuel investments are still concentrated in low-income and emerging economies.
Fossil fuel investments mirror natural resource reserves: Among countries receiving public energy investments, it is clear that the allocation of energy investments closely reflects the distribution of natural resources.
Recommendations
Given these findings, we offer policy recommendations for public finance institutions and their governments.
Public finance institutions should:
Set targets consistent with 1.5°C warming: Public financial institutions should set concrete targets to reduce the scope 1, 2, and 3 emissions in their portfolios.
Fully commit to the Glasgow Public Finance Statement: This means implementing exclusion policies across the entire fossil fuel supply chains without exceptions, loopholes or indirect financing, and shift all energy lending to support clean energy projects.
Support the clean and just energy transition in low-income and emerging economies: As many countries are still recovering from the fiscal damage of the pandemic, public financial institutions should provide their fair share of debt cancellation to facilitate a clean and just energy transition in those economies.
Enhance transparency: Disclose detailed data on projects financed by intermediaries and introduce adequate due diligence to ensure that funds are being channeled in line with the institution’s climate goals.
The governments of public finance institutions should:
Make public finance for clean energy a priority
Actively engage with public financial institutions
Mandate climate-related financial risk disclosures from public financial institutions
1. Fossil Fuel Investments Dwarf Clean Energy
Between 2015 and 2021, fossil fuel projects received more than 3 times the investments that clean energy and other projects did (Figure 1).
In aggregate, $435 billion were invested in fossil fuel projects during that period, compared to $101.7 billion in clean energy projects. Among fossil fuel categories, natural gas projects attracted the most investments ($171 billion), followed by the combined oil and gas category ($106.5 billion) and coal ($71.5 billion) over the same period. This relative magnitude of investments across fossil fuels roughly reflects the global energy mix, where oil and natural gas account for more than 50% of all primary energy consumption over the same period.
But Oil and Coal Investments Are On a Decline
But as the temporal patterns shown in Figure 2 suggests, investments in oil and coal have followed a downward trend since 2016, declining by 380% between 2016 and 2021. At the same time, however, investments in natural gas projects have more than compensated for their decline, and investments in clean energy have generally stayed flat over the same time period.
As we will discuss below, the decline in oil and coal investments is attributable to international pressures on public finance institutions to reduce fossil fuel exposure, diminishing demand for new fossil fuel production in recipient countries, and the COVID pandemic.
2. China, Japan, South Korea, and Canada are the Most Active Fossil Fuel Funders
Disaggregating by country, we see which countries are the most prolific funders of energy projects abroad. Figure 3 orders G20 countries (excluding the European Union) by the amount of financing they directed toward energy projects between 2015 and 2021, separated by energy category.
What is immediately clear is the three major East Asian economies are the top funders in energy projects globally. Between 2015 and 2021, China invested $154.6 billion in fossil fuel, clean, and other energy projects, while Japan provided $92.6 billion and South Korea made $78.9 billion. Consistent with Figure 1, investments in fossil fuel projects dominate the top 3 financing countries’ investments.
Outside of the three East Asian countries, Canada is a large fossil fuel funder, with most of its public finance directed at oil and gas-related projects.
During this time period, coal-related activities remained an important part of several countries’ public finance portfolios. China, Japan, India, South Korea, and Indonesia were the top funders of coal-related activities, both domestically and internationally. While their support for unabated coal has declined during these years, many public finance institutions in these countries continue to finance coal in some way.
A Handful of Countries Spend More on Clean Energy
Several countries stand out for their large investments in clean energy. Brazil’s clean energy investments far outpace its funding for fossil fuels. It directed $23.8 billion to domestic clean energy projects (particularly wind power) and $43.6 billion to the “other” category, most of which are large hydroelectric, nuclear and biomass projects. Nearly half of Germany’s and the majority of France’s public investments also went to clean energy.
3.Fossil Fuel Investments Decline While Clean Energy Investments Climb
We now narrow our focus to the top five financing countries shown above. These five countries – China, Japan, South Korea, Canada, Brazil – together account for 70% of total G20 public finance for energy. We look at how their investments have changed over time. Figure 4 shows their investments in fossil fuels internationally.
The first striking trend is the spike in China’s investments in fossil fuel projects in 2016 to nearly $48 billion. This coincides with the period in which China was particularly active in energy sector lending under its Belt and Road Initiative (BRI). Launched in late 2013, the BRI is China’s sweeping plan to promote infrastructure development across Africa, Asia, and Europe. By one estimate, China’s international investments in the energy sector under the BRI increased by 130% from 2015 to 2016. After 2016, however, Chinese investments in the energy sector declined and were reallocated to other sectors.
Another notable pattern is the precipitous decline in fossil fuel investments between 2020 and 2021, driven in particular by South Korea and to a lesser extent by Japan and Canada. In one year, fossil fuel finance dropped from $43.3 billion to $16.2 billion, a 62.6% decline.
This trend points to both promising and grim developments to come.
Multilateral Commitments and Declining Demand Suggest Reduced Fossil Fuel Investments in the Future
On the one hand, increasingscrutiny over enormous fossil fuel subsidies is pressuring governments to halt funding fossil fuel projects globally. As a result of this mounting pressure, 34 countries and 5 public finance institutions signed the Glasgow Public Finance Statement at the 26th UN Climate Change Conference of the Parties in November 2021. This statement was the first international commitment to end direct international public finance for fossil fuels by the end of 2022 and instead prioritize public finance for clean energy. If all signatories follow through with the agreement, it could shift $28 billion a year out of fossil fuels and into clean energy. Following this agreement, South Korea, Japan, and China – some of the largest coal financiers – announced that they will stop state-backed overseas coal finance by the end of 2021.
In parallel to these curtailment commitments, the demand for such investments may also be on the decline. Historically, many lower and middle-income countries embraced the growth of coal-fired power generation, and public investments by larger economies often filled that demand. But more recently, as the World Resources Institute points out, some countries receiving such funding are losing interest in coal investments for three reasons.
Environmental and social permitting is becoming more stringent because of resistance from local communities. Facing pushbacks, governments in Vietnam, Bangladesh, Indonesia, Pakistan and the Philippines have made decisions to cancel, delay, or reduce the development of coal power plants in the last several years.
The COVID-19 pandemic has left many developing and middle-income countries with large, running bills fixed on their coal capacity tariffs.
Costs of new coal-fired power plants are becoming higher than new renewable energy projects in 35 countries when taking into account transportation, storage, and environmental costs.
In line with the eroding attractiveness of fossil fuel investments, funding from public finance institutions in clean energy has been on the uptick since 2019 (as shown in Figure 5), perhaps in anticipation of an international agreement like the Glasgow Public Finance Statement. This is consistent with the overall increase in clean energy investments identified by the IEA in its latest World Energy Investment 2023 report.
But Loopholes Point To Persistent Fossil Funding
Yet at the same time, there are reasons to believe public financing in fossil fuels will continue.
Many of the signatories of the Glasgow Public Finance Statement have included loopholes in their fossil fuel exclusion policies, allowing them to continue fossil fuel investments. For example, fossil fuel funding by Canada’s export credit agency, Export Development Canada (EDC), declined in 2021 after pledging to end new direct financing to international fossil fuel companies and projects as of January 1, 2023. Despite this, EDC’s net-zero policy leaves room for additional oil and gas investments by aiming for a 45% reduction in exposure to 6 carbon intensive sectors (including upstream oil and gas, petrochemical, refining, and thermal power generation) below 2018 levels by 2023. In essence, governments and institutions often pledge to end new investments while maintaining existing funding relationships.
In addition to including loopholes, several public finance institutions have simply violated their pledges to end fossil fuel funding. While most of the signatories of the Glasgow Statement have kept their promise, an update by Oil Change International in October 2023, however, shows that six countries – the US, Italy, Germany, Switzerland, Netherlands, and Japan – are violating their commitments to end international public finance for fossil fuels. In total, they have approved at least $5.2 billion in oil and gas projects in 2023.
4. The Majority of Clean Energy Investments Flow to Wealthier Countries
We now shift our attention from the countries that invest in energy projects (financing countries) to countries in which these projects are developed (recipient countries). We first analyze the relative financing directed at recipient countries that are G20 members and those that are not. Recall that all financing countries in the Public Investments for Energy Database are G20 members.
Figure 6 shows the amount of investments received by G20 and non-G20 nations between 2015 and 2021. Strikingly, while most public finance for energy flows to non-G20 recipient countries, most of the clean energy investments are directed at G20 countries. In other words, financing for clean energy from the developed world is flowing back into the developed world.
The differences are stark. While non-G20 countries received $326.5 billion in energy investments (not including the “Other” category), less than 10% of this total was for clean energy. On the other hand, G20 countries received $210.6 billion in investments, 33% of which was for clean energy projects.
Low- and Middle-Income Countries Face Barriers to Clean Energy Investments
The fact that most energy investments by public institutions go to non-G20 countries itself is not surprising. After all, the mandate of most development finance institutions’ includes facilitating international capital flows to foster economic growth in developing countries.
What is more complicated is explaining why fossil fuel investments account for a disproportionate share of the total investments. While non-G20 countries encompass an enormous range of development levels and characteristics, the World Bank finds that low- and middle-income countries face a “triple penalty” when it comes to financing clean energy:
Despite tight budgets, they pay more for less clean energy: Governments in low- and middle-income countries have limited fiscal space to make catalytic public investments and limited consumer ability to pay for cost increases. At the same time, these countries have less access to private capital and face higher costs of capital compared to high-income countries. The cost of clean energy technologies (solar panels, some wind turbines, etc.) has also increased as a result of global economic and geopolitical uncertainties since 2020.
They risk being locked out of solar, wind, and energy efficiency projects: The main clean technologies such as wind and solar power and energy efficiency face a disadvantage in lower- and middle-income countries because of their higher up-front capital requirements compared to coal and gas power. This is despite the fact that coal and gas power incur higher fuel costs over their operating lifetimes. Without access to cheap capital, clean energy technologies remain unaffordable in these countries.
They are locked into fossil fuel generation: Despite its higher and volatile operating costs over the long run, governments are locked into coal and gas power plants. This is because many state-owned utilities have long-term power purchase agreements with plant owners, and because of the financial and up-front cost barriers identified above.
The COVID-19 pandemic exacerbated these challenges, worsening budget deficits and indebtedness of governments and public utilities in developing economies.
These barriers to clean energy investments in many recipient countries and the lack of airtight commitments by financing countries to stop fossil fuel investments mean that G20 public finance institutions are naturally incentivized to invest in fossil fuel projects to support economic growth and energy access in recipient countries.
We now disaggregate recipient countries further. Figure 7 shows the top 20 recipient countries by energy category between 2015 and 2021. Figure 8 shows the top 5 recipient countries, ordered by the amount of fossil fuel and clean energy financing they receive from the top 6 financing countries.
What is most evident in Figure 8 is that the pattern of energy investments flowing to recipient countries closely reflects the distribution of natural resources. For example, investments in oil as well as the “oil and gas” category largely target Brazil, Canada, Egypt, the Middle East, and Angola - all countries with large oil reserves. Similarly, public investments flowing into Russia, Mozambique, Indonesia, the US, and Nigeria largely fund natural gas projects, exploiting these countries’ large natural gas reserves.
Taking Russia as an example, we see that between 2015 and 2021, 94% of the $60.6 billion that it received went to fossil fuel projects. Natural gas constituted the majority (83.9%) of these investments. In terms of the sources of investments, 43% of all investments came from China, 26.6% from Russia itself, and 13.8% from Japan. Major European countries also had minor stakes in Russia’s energy sector development. However, Russia’s invasion of Ukraine in February 2022, and the western sanctions and capital flight that it triggered have dealt a heavy blow to these investments. According to one estimate, investments in Russia’s upstream oil and gas sectors have plunged by $15 billion. Public investments were very likely part of those lost investments.
Another notable example of a recipient country rich in natural resources is Mozambique, where 95.7% of the $27 billion in investments went to natural gas extraction. Since the discovery of massive offshore gas fields in northern Mozambique in 2010, multinational companies began developing these gas fields with the support of export credit agencies. The first offshore gas project came online in 2022. LNG investments in Mozambique – and elsewhere in Africa – are set to increase over the next several years. As the EU scrambles to reduce its dependence on gas imports from Russia, it is eyeing this continent as a valuable source of LNG.
Another high-level pattern in Figure 8 is that several countries received large amounts of investments in the coal sector. For example, 89.5% of total investments in Vietnam are directed at coal projects. All of these coal investments in Vietnam originated in Japan, China and South Korea. Bangladesh, too, is a large coal finance recipient, and the Japan International Cooperation Agency is responsible for 93.5% of its coal investments.
On the other hand, substantial investments are directed at clean energy projects in a handful of countries. In Angola, Argentina, Brazil, India, France, and the UK, clean energy investments account for one-fourth or more of all public investments in energy. In several of these cases, a bulk of the clean energy investments came from their own public finance institutions. In France, for example, domestic public-sector banks Bpifrance and Caisse des dépôts et consignations together accounted for 88% of the clean energy finance that the country received.
In the case of Brazil, nearly 70% of investments are its own domestically-oriented investments in clean energy and “other” projects. The Brazilian Development Bank was responsible for 96% of its clean energy investments in 2019-2021. But as Figure 9 makes clear, the other major financier in Brazil’s energy development was China, which accounted for 24% of all public investments in Brazil during this period, almost all of which was in fossil fuel activities.
6. How Governments and Public Finance Institutions Can Become Clean Champions
As tripling global renewable energy capacity and transitioning away from fossil fuels were landmark agreements to come out of COP28, a close scrutiny of public finance institutions is timely. As public finance and government subsidies have traditionally favored fossil fuels, decisively pivoting these sources of finance toward clean energy would signal to the private sector that the age of fossil fuels has come to an end, greatly increase financial flows to clean energy sources in low and middle income countries, and make it possible for the world to reach the landmark agreements.
To this end, we refer to the Climate Policy Institute’s Framework for Sustainable Finance Integrity to put forth the following recommendations for both public finance institutions and G20 financing countries.
Recommendations for Public Finance Institutions
Set targets that are consistent with pathways in limiting warming to 1.5°C. Public financial institutions should set targets to reduce the portfolio scope 1, 2, and 3 emissions by 22%-32% on absolute level by 2025, and by 40%-60% by 2030. Setting a target for scope 3 emissions is particularly important, because it will incentivize financial institutions to make rapid changes early, allowing additional time to address developing economies and difficult-to-decarbonize sectors.
Fully commit to the Glasgow Public Finance Statement. Public financial institutions should implement exclusion policies across the entire fossil fuel supply chains without exceptions, loopholes or indirect financing. Instead, public financial institutions should also aim to shift 100% of energy lending to support zero-carbon energy projects and curtail support for unabated fossil fuel-related projects where credible transition strategies are absent.
Support the clean and just energy transition in low-income and emerging economies. Many low-income and emerging economies are still recovering from the fiscal burden of pandemic response. Public financial institutions should provide their fair share of debt cancellation to facilitate a clean and just energy transition in those economies. Debt cancellation should be through the channels of grants or highly concessional finance, paying loss and damage support, and engaging constructively in broader international reparations fora.
Enhance transparency. Disclose detailed information on projects and sub-projects financed by financial intermediaries and introduce adequate due diligence to ensure that intermediaries and project partners are channeling funds in line with the institution’s climate goals. This will enhance transparency around climate finance for all stakeholders.
Recommendations for Governments
Make public finance for clean energy a priority. Along with fossil fuel subsidies (not explored in this article), investments by public financial institutions is a policy domain directly under the control of governments. Aligning these sources of finance with the Paris Agreement goal of limiting average global temperatures to 1.5°C and the Sustainable Development Goals of affordable and clean energy and climate action should be a top priority for the governments of high-income countries.
Actively engage with public financial institutions. Governments are shareholders of public financial institutions, and as such they should engage with the institutions to support the implementation of their climate action and recommendations outlined above. Governments should also increase fiscal and human resources for public financial institutions to successfully implement these measures.
Mandate climate-related financial risk disclosures from public financial institutions. This can take the form of adopting the recommendations published by the Taskforce on Climate-related Financial Disclosures.
7. Conclusion
The analysis of public finance institutions' investment trends in the energy sector paints a picture of a transition in progress, but one that is not happening fast enough.
While the surge in private investments towards clean energy is a positive sign, the continued preference for fossil fuels among public finance institutions in several large economies is a cause for concern. This investment pattern, particularly prevalent in G20 countries, demonstrates a significant lag in public sector alignment with global climate objectives. The time has come for public finance institutions to take bold steps in supporting clean energy projects, aligning their portfolios with the Paris Agreement goals.
This shift will require a reevaluation of current investment strategies, greater transparency, and a commitment to supporting the energy transition in all economies, especially those that are less developed. The transition to a sustainable energy future is not just an environmental necessity but also an economic opportunity. To make this transition successful, both public finance institutions and governments must work in tandem, setting clear targets, enforcing climate-related disclosures, and making clean energy a cornerstone of their investment strategies.
Notes on the database and our approach
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The Rise of Community Solar Explained: A Data-Driven Analysis of the New York Market
Hydrogen has the potential to cut greenhouse gas (GHG) emissions from sectors in which direct electrification is difficult. These include heavy industry like cement and steel manufacturing, heavy-duty and long-distance transport, aviation, shipping, and chemical feedstocks. In recent years, hydrogen has gained much attention as a clean-burning fuel and energy carrier to decarbonize these hard-to-abate sectors. The International Renewable Energy Agency estimates that hydrogen will account for as much as 12% of global energy use by 2050.
But until recently, the pace of growth in hydrogen production and uptake has been far slower than what is needed to meet that estimate. What's more, the vast majority of hydrogen today is produced using fossil fuels, emitting sufficient levels of GHGs to negate hydrogen's climate benefits.
Hydrogen is a simple molecule made up of two hydrogen atoms. How hydrogen is produced, however, determines whether it is a climate solution or part of the problem. Here are the most common methods of producing hydrogen and their colors.
Low-carbon hydrogen
Green
Produced by splitting water molecules with renewable electricity through water electrolysis.
Green hydrogen has the lowest carbon intensity and is therefore the cleanest production method.
Blue hydrogen is often considered “low-carbon,” but methane emissions from the natural gas value chain is still a major amplifier of climate change.
High carbon-intensity hydrogen
Gray
Produced using natural gas with no attempt to cut emissions.
Brown
Produced using black coal or lignite (brown coal).
To scale up clean hydrogen, market forces aren’t enough. Government incentives, investments, and regulatory reforms are critical for establishing a large and mature industry for clean hydrogen. Policies are also needed to bring down the cost of clean hydrogen. Today, hydrogen produced using natural gas is $2.13 per kilogram (kg) on average, while clean hydrogen costs $6.40/kg. This gap needs to be closed for clean hydrogen to be widely used as a fuel.
In this article, we take a look at the state of hydrogen strategies around the world. We restrict our analysis to only those strategies with quantitative targets for price, demand or supply, and disregard strategies that are purely aspirational. Referring to the National Hydrogen Strategies and Roadmap Tracker maintained by Columbia University’s Center on Global Energy Policy and the International Energy Agency’s Global Hydrogen Review 2023, we collected information on the demand, price, and supply targets in all of the national- and supra-national (in the case of the European Union) hydrogen strategies that we are aware of to date.
Overarching hydrogen strategies
Why do governments formulate hydrogen “strategies?”
As we will see below, many governments around the world have formulated strategies to build up the hydrogen industry in their jurisdictions. Strategies are comprehensive and coherent sets of policy measures to encourage the growth of an industry. In the case of hydrogen strategies, they often spell out the goals and steps for the growth of equipment manufacturing, production, transport, storage, and usage of hydrogen.
Why do governments prefer to formulate strategies rather than piecemeal policies? Because strategies offer several advantages over individual policy measures:.
Long-term consistency and coordination: Hydrogen strategies aim to provide long-term policy certainty, common targets, and coordination across different government agencies (such as those responsible for energy, environment, and transport policies) and the private sector. Piecemeal policies often change with each new government, undermining the credibility needed for firms to make the necessary long-term investments.
Addressing systemic issues: Hydrogen strategies try to tackle the systemic roots of problems, like institutional biases against long-term planning, rather than just addressing individual market failures in an isolated fashion.
Aligning individual policies toward overarching goals: When government agencies and private-sector firms agree on overarching goals spelled out in strategies for the hydrogen industry, it’s easier to design individual policies to be aligned with those goals. In the absence of explicit goals, policies to encourage the growth of the hydrogen industry may be uncoordinated.
Avoiding political capture: Hydrogen strategies can be designed with safeguards to reduce the risk of policies being excessively influenced by politically powerful groups, whereas piecemeal policies are more vulnerable to such influence.
Timeline of hydrogen strategy adoptions
Research on hydrogen fuel cells began in the late 19th century, and serious R&D began in response to the oil shocks of the early 1970s. But policymakers only began formulating comprehensive strategies once the need to decarbonize hard-to-abate sectors became acute. In other words, the wave of national hydrogen strategies is truly a recent phenomenon (Figure 1).
Figure 1: Number of new national hydrogen strategies, 2017-2023
Source: Center on Global Energy Policy and IEA “Global Hydrogen Review 2023”
The first comprehensive national hydrogen strategy was published in Japan in 2017, followed by France in 2018, and Australia, New Zealand, and South Korea in 2019. Eleven countries published strategies in 2020, 16 in 2021, nine in 2022, and 12 countries in 2023. An increasing number of countries have also revised their original strategies in the same time period.
In the U.S., the federal hydrogen program has been running for two decades. But in September 2022, the Department of Energy released a draft version of the National Hydrogen Strategy and Roadmap and published the final version in June 2023. The strategy and roadmap serves as a summary of the current state of U.S. hydrogen production, transport, storage, and use, as well as projecting demand scenarios for clean hydrogen and its contribution to national decarbonization goals.
Table 1: List of countries that published a hydrogen strategy
Argentina, Brazil, Chile (1st revision), Colombia, Denmark, France (2nd revision), Hungary, Luxemburg, Netherlands (1st revision), Poland, Russia (1st revision), Slovakia, South Africa, Sweden, U.K., U.S.
2022
Austria, Belgium, China, Costa Rica, Croatia, Germany (1st revision), Namibia, Oman, Singapore, South Africa (1st revision), U.K. (1st revision), US (1st revision), Uruguay
2023
Argentina (1st revision), Australia (1st revision), Brazil (1st revision), Ecuador, Finland, Germany (2nd revision), India, Ireland, Japan (1st revision), Kenya, New Zealand (1st revision), Panama, Peru, Romania, Russia (2nd revision), Sri Lanka, Turkey, U.A.E., U.K. (2nd revision), U.S. (2nd revision)
Source: Center on Global Energy Policy and IEA “Global Hydrogen Review 2023”
Why revise?
Many countries have revised or updated their hydrogen strategies after their initial publication. Why were revisions necessary?
Pandemic recovery: Some of the early revisions were prompted by the economic recession caused by the COVID-19 pandemic. Governments saw an opportunity to couple hydrogen investments with pandemic recovery measures.
Greater policy precision: Some initial hydrogen strategies were more like statements of aspiration, which lacked precise quantitative targets. As governments zeroed in on their specific targets and roadmaps, some of them published revised strategies.
Changes in global energy context: The declining cost of renewable energy in many parts of the world, the disruption in energy markets caused by Russia’s invasion of Ukraine, the proliferation of competing hydrogen strategies, and other developments changed the international economic and energy contexts, prompting many governments to reconsider their initial strategies.
Demand-side targets
Global hydrogen demand reached 95 million tons in 2022, nearly a 3% increase over 2021. This demand is concentrated in traditional applications such as the refining, chemicals (as feedstock), and steel (as a reducing agent) sectors. Hydrogen uptake in new applications in heavy industry, production of hydrogen-based fuels (e.g., ammonia, synthetic aviation fuel, etc.), which will be key for the clean energy transition, remains negligible, accounting for less than 0.1% of the global demand. This means that the 3% increase in hydrogen demand has had no benefit for climate change mitigation.
Without strong demand, low-carbon hydrogen project developers cannot secure investments. Creating demand for low-carbon hydrogen, which will be significantly more expensive than hydrogen produced using carbon-intensive processes or fossil fuels, will require strong policy push.
This is why most of the hydrogen strategies published so far include explicit targets for hydrogen demand and use. Figure 2 shows the number of national hydrogen strategies that specify a demand target.
Figure 2: Hydrogen strategies with demand targets
Source: Center on Global Energy Policy and IEA “Global Hydrogen Review 2023”
Figure 3: Sectoral applications of demand targets
Source: Center on Global Energy Policy and IEA “Global Hydrogen Review 2023”
Why set targets?
These hydrogen strategies are notable for their relatively precise quantitative demand-side, supply-side, and price targets. But why are quantitative targets important? There are a few reasons for this.
Government and policy accountability: By setting targets, policymakers create a long-term accountability mechanism for current and future policies to adhere to.
Market signals: By explicitly announcing a specific hydrogen price, use, and production amount, these targets signal to industry players and investors about the expected growth in hydrogen across its various sectoral applications. In turn, this signal can encourage further investments into hydrogen infrastructure.
Track progress toward climate goals: Hydrogen strategies are often an important part of countries’ decarbonization goals. Price, demand, and production targets act as landmarks along their hydrogen roadmaps, which often align with their emission reduction pathways.
Table 2: Demand target examples in the industrial, road transport, other transport, chemicals, and power sectors
Sectoral applications
Country/Target
Industrial
Australia: Replace 80% of fossil-based hydrogen with climate-neutral hydrogen in energy intensive industries, including iron and steel manufacturing, by 2030
EU: Green hydrogen to account for 42% of hydrogen used in the industrial sector by 2030
Spain: Green hydrogen to account for at least 25% of hydrogen used in the industrial sector by 2030
Road Transport
China: Deploy 50,000 fuel cell vehicles by 2025
Poland: Deploy between 100 and 250 fuel cell buses by 2025
South Korea: Deploy 30,000 fuel cell commercial vehicles by 2030
Other Transport
Panama: Use green hydrogen or its derivatives for 30% of the fuel used in aviation by 2050
Romania: One project of using hydrogen in passenger transport by waterway
Chemicals
Australia: Replace 80% of fossil-based hydrogen with climate-neutral hydrogen in the chemicals sector by 2030
Japan: Use ~3 million tons of hydrogen per year throughout the economy, including in chemicals manufacturing, by 2030
Power
Romania: Commission 16 GW of combined-cycle turbines compatible with 50% green hydrogen by 2030
Singapore: Hydrogen could meet up to 50% of electricity demand by 2050
Slovakia: Use of 5,000 tonnes of hydrogen in the power sector by 2030
Source: Center on Global Energy Policy and IEA “Global Hydrogen Review 2023”
Supply-side targets
Meeting increased demand implies greater production and supply. Hydrogen production is highly energy intensive. How that energy is generated is the crux of the challenge in scaling up hydrogen as a climate solution. Today, more than 99% of the hydrogen used globally is produced using fossil fuels. Far from acting as a solution, fossil fuel-based hydrogen exacerbates the climate crisis.
While there is still no definition for these terms, there is an emerging consensus that “low-carbon” hydrogen refers to hydrogen produced via water electrolysis with renewable electricity or nuclear energy, or fossil fuels with high levels of carbon capture. The technical and economic feasibility of scaling up these sources of hydrogen is yet to be determined.
Nonetheless, many national hydrogen strategies set targets for low-carbon hydrogen production. Figure 4 shows the number of hydrogen strategies with explicit supply targets.
Figure 4: Hydrogen strategies with supply targets
Source: Center on Global Energy Policy and IEA “Global Hydrogen Review 2023”
These targets can either explicitly state the amount of hydrogen to be produced or the electrolyzer capacity to be built by a given date. Table 3 presents examples of supply-side targets.
Table 3: Examples of supply-side targets in national hydrogen strategies
Country
Supply-Side Target
Argentina
Produce 5 million tons of hydrogen per year by 2050 (80% of which will be for export)
Install 30 GW of electrolysis capacity and 55 GW of renewable electricity generation
Chile
5 GW of electrolysis capacity (operating & under development) by 2025
China
Produce 100,000-200,000 tonnes of green hydrogen by 2025
Peru
Install 1 GW of electrolyzer capacity by 2030 and 6 GW by 2040
U.S.
Produce 10 million metric tonnes of clean hydrogen per year by 2030, 20 MMT per year by 2040, and 50 MMT per year by 2050
Source: Center on Global Energy Policy and IEA “Global Hydrogen Review 2023”
Price targets
A critical element of creating a viable low-carbon hydrogen industry is to scale up hydrogen production to the point where the price of low-carbon hydrogen is competitive with fossil fuels and fossil-based hydrogen that are used today. If low-carbon hydrogen does not become price competitive with existing fuels, plant operators and fleet operators simply will not use it.
According to BloombergNEF’s analysis of hydrogen prices worldwide, gray hydrogen costs $0.98-$2.93 per kilogram (kg) to produce. Blue hydrogen costs $1.8-$4.7 per kg and green hydrogen costs $4.5-$12/kg. In every market, green hydrogen is more expensive than its gray counterpart. Table 4 shows the average of these costs.
Table 4: Average production cost of gray, blue, and green hydrogen in 2023
Color
Definition
Average production cost in 2023
(per kg)
Gray
Produced from natural gas without abatement
$2.13
Blue
Produced from natural gas with carbon capture
$3.10
Green
Produced from water electrolysis using renewable electricity
Price is an outcome of supply, demand, and market sentiment. While most governments don’t directly mandate prices, many hydrogen strategies still set price targets for policymakers and industry players to aim for and to set investor expectations. Figure 5 compares the number of strategies that contain explicit price targets with those that do not.
Figure 5: Hydrogen strategies with price targets
Source: Center on Global Energy Policy and IEA “Global Hydrogen Review 2023”
Among the strategies that contain price targets, reaching for between $1 and $2 per kg of hydrogen is common. Yet there is little consensus on the production methods of this hydrogen — many strategies are ambiguous on this point, using terms such as “clean” hydrogen without specifying the production method. These strategies also set targets for different dates into the future, often using 2030 and 2050 as landmarks. Table 5 shows some examples of these targets.
Table 5: Examples of price targets in national hydrogen strategies (target years are in parentheses)
Country
2030 - 2035
2040 - 2050
Argentina
$1.1/kg for blue H2 (2030)
$2.8-6.4/kg for green H2 (2030)
$1.4-1.7/kg for green H2 (2050)
Australia
$1.32/kg for clean H2 (2030)
Chile
<$1.5 /kg for green H2 (2030)
France
$1.6/kg (2030)
Japan
$2.11/kg (2030)
¥20/Nm3 (2050)
Peru
$1.6/kg (2030)
$1.3/kg (2040)
$1.0/kg (2050)
South Africa
$1.60/kg for green H2 (2030)
Turkey
<$2.5/kg for green H2 (2035)
<$1.2/kg for green H2 (2053)
USA
$1/kg for clean H2 (2031)
Notes: Japan’s price targets are set in normal cubic meters (NM3). NM3 = 0.08988kg. JPY 154.71 = $1.00; AUD 1.52 = $1.00
Source: Center on Global Energy Policy and IEA “Global Hydrogen Review 2023”
How feasible these price targets are varies enormously depending on the country and the analysis. One source estimates that green hydrogen production costs could decrease by 50% by 2030, and could be in the range of 1 euro ($1.08)/kg by 2050 in the Middle East, Africa, Russia, China, the U.S. and Australia. On the other hand, another source expects green hydrogen cost will only decline to a range of $3 - $7/kg by 2050.
In short, the proliferation of strategies and policies will certainly increase hydrogen production and use and reduce costs, but to what extent they will achieve each of these goals is far from certain.
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