Report | 2022

Fossil Fuel Transition Strategies

Global Energy Transformation Guide: Electricity

By Cara GoldenbergAnibal Gomez-ContrerasLeia GuccioneGenevieve LillisMatt Sugihara
Download the report below

Declining costs, technological advances, and rising energy security concerns have resulted in renewable energy recently usurping coal and gas as the lowest-cost way to reliably power most countries’ economies. This cost advantage has been even more pronounced in the past year given the significant volatility in fossil fuel prices due to Russia’s war in Ukraine. To reliably transition the coal fleet, minimize the build-out of new gas, and mitigate customer and ratepayer impacts, utilities and governments are taking advantage of new financing and reinvestment opportunities that can help ease and support the transition to clean energy.

Through research and interviews with experts around the globe, RMI has compiled examples and data to describe how power sector leaders are leveraging fossil transition strategies to make progress on energy transition priorities. Specifically, this report:

  • Highlights why innovation is critical to making progress in the transition from fossil fuels
  • Explains emerging global trends and associated challenges and opportunities
  • Describes how fossil fuel transition strategies can advance seven key outcomes for successful global energy transformation
  • Articulates the edge of innovation for different countries and where attention is needed most
  • Spotlights case studies to better illustrate what is being attempted across the industry and to share the experiences of practitioners

This report is part of RMI’s Global Energy Transformation Guide.

Related Spotlights

United Kingdom

Coal Transition in the United Kingdom


Kenya’s Growth through Clean Energy


Overcoming Long-Term Fossil Fuel Generation PPAs in Chile

Canada and Germany

Stakeholder-Driven Just Transition in Canada and Germany

Coal Transition in the United Kingdom

This spotlight primarily advances the priority outcomes highlighted below. These outcomes are further described in the complementary Points of Progress report and in the Fossil Fuel Transition Strategies report.

Exhibit 1: Priority Outcomes for Global Energy Transformation

Britain’s four remaining coal-burning power plants are zombies, all but dead. Within a couple of years they will be closed and Britain will probably never burn coal for electricity again.

(The Economist, February 2021)

Once the world’s largest coal consumer, the UK is on the cusp of entirely phasing out coal generation, with the last plant slated to close in 2024. The UK’s experience represents perhaps the fastest example of ending coal generation in advanced economies, although there have been many lessons learned, especially in ensuring a just transition.

The UK used several key environmental and carbon policy mechanisms, primarily through its energy market reforms in 2013, to accelerate the phaseout of coal. Simultaneously, coal became increasingly uncompetitive in the wholesale market due to falling electricity prices, supported by the expansion of clean energy, notably a world-leading offshore wind industry. The UK’s transition is notable both for its pace and for its high levels of coal-to-renewables development, rather than transitioning to gas or other thermal resources.

  • The UK is an important lodestar showing rapid coal transition is possible in a mature, developed economy. The establishment of a carbon price made coal uneconomic with unexpected rapidity.
  • Although gas generation is still a sizable part of the UK’s overall generation portfolio, the expansion of the renewable energy industry and large gains in energy efficiency have made up much of the difference that coal left. Early investments in offshore wind have paid dividends with tumbling costs.
  • The UK’s decades of experience navigating the coal transition have yielded instructive lessons for other economies on a just transition. While countries such as Canada and Germany have devoted effort to transition planning, the UK’s market-oriented policies through the 1990s largely left coal communities with major economic and structural challenges, which remain today.
  • While the UK’s experience is especially applicable to advanced economies eyeing ways to phase out coal, coal-heavy industrializing nations may also benefit as they begin planning for their transition. The policy levers and lessons learned in supporting coal communities will be instructive in the coming decades.
Context of Coal in the UK

The UK was once a dominant coal-producing economy, but the industry declined throughout the 20th century. Coal-fueled generation initially declined in the early 1990s during the “dash for gas,” when large gas-fired plants began replacing coal during privatization of the energy sector. Following that shift, coal remained relatively steady until the mid-2010s.

Environmental Policy

Importantly, the UK Government was early in recognizing the need to decarbonize its energy system. A seminal white paper published in 2003 set the stage for later investment decisions in light of the UK’s already aging coal fleet. In 2008, the UK passed the Climate Change Act, which set multiyear carbon budgets, further challenging the deployment of new coal generation.

In the 2010s, the enforcement of new EU emissions standards, namely the Large Combustion Plants Directive, caused a reduction in smaller coal plants, because retrofits to reduce sulfur emissions were considered uneconomic. Of the 17 plants then operating, six closed because of this directive.

Policies and Energy Market Reform Expand Renewable Energy

Over the same time frame, the UK Government introduced additional measures to drive adoption and uptake of renewables. First, it introduced a renewables obligation for Britain in 2002 and Northern Ireland in 2005, requiring all electricity suppliers to provide a certain portion of electricity from renewable sources. The targets were set annually by the Department of Energy and Climate Change, and they created a market for Renewables Obligation Certificates, which generators would sell in addition to wholesale electricity.

During electricity market reforms introduced in 2013, the UK also created a Contracts for Difference (CfD) program aimed at stabilizing new development of renewables. The program played a major role in expanding offshore wind generation, which ultimately made possible the UK’s first coal-free day in April 2017. The CfD auction process essentially offers generators a fixed price over a long payback period by paying the difference between the “strike price,” which is set at the auction, and a particular market reference price. This guarantees the generator a long-term source of income to underpin financing and ensure returns on the investment. These support mechanisms have catalyzed renewable energy development (especially offshore wind), but they have been criticized for their tendency to pass through additional costs to consumers.

The UK markets also benefited from access to capital though facilities such as the UK Green Investment Bank which provided initial support to high-cost, high-risk investments in nascent industries. It also succeeded in mobilizing private capital to support renewable generation. By the time it was sold to Macquarie Group in 2017, the Green Investment Bank had committed $4.7 billion of its own financing toward renewable projects, as well as $10 billion of private financing.

The lateral shifts from coal to renewable deployment, driven principally by subsidies and taxes, did raise prices for consumers, especially industries. However, energy efficiency improvements occurring in parallel with the market reforms generally kept bills fairly consistent. Exhibit 3 shows that average electricity prices for all users remained generally the same before and immediately after the reforms.

Carbon Pricing

Carbon pricing was perhaps the most influential lever in the UK’s transition away from coal. This pricing mechanism is largely considered the most efficient method to capture the external costs of carbon. Even while coal was subsidized implicitly — for example, through the formation of capacity markets — the implementation of carbon pricing made coal especially uncompetitive during the mid-2000s.

The UK trialed carbon pricing between 2002 and 2005 in advance of the EU Emissions Trading System (EU ETS). The EU ETS operates as a cap-and-trade system in which freely allocated permits allow power generators to pursue the most cost-effective emissions reductions. However, carbon prices remained relatively low following its deployment.

As part of the 2013 electricity market reforms, the UK introduced an additional carbon tax, the Carbon Price Support (CPS), which set an effective price floor. The CPS represented an escalating tax that is additive to the EU ETS pricing, which was £18 per ton of CO2 equivalent as of 2021. This tax, combined with rising fuel costs, has created a major correction to coal economics, making coal unprofitable in most cases and accelerating the closeout of coal generation. Although Brexit meant the UK formally exited the EU ETS, the UK has since deployed the UK Emissions Trading Scheme, which broadly mirrors the EU ETS and includes the CPS addition.

Lessons on a Just Transition

The decline of coal in the UK has been notably turbulent, especially due to the country’s strong economic linkages to coal production and generation. At its peak in the 1960s, the UK coal industry employed more than 600,000 people. By 1997, nearly 90 percent of those jobs were gone.

Although the power of organized labor was already in decline, the tumultuous miners’ strikes in 1984 and 1985 substantially reduced labor unions’ political clout. This was further exacerbated by a large decline in coal demand through the 1990s during the “dash for gas,” as well as by the privatization of coal mines. That transition, and the subsequent closure of unprofitable mines, left coal-dependent communities with major workforce transition issues. The UK tried to support workers via redundancy packages (with around 6–12 months of wages and welfare benefits), as well as retraining support.

While some jobs transitioned, ultimately many were left behind. The strongly market-driven nature of the coal decline resulted in a lack of long-term, forward-looking plans, which made the transition more difficult for communities to navigate. Additionally, rebuilding coal communities takes a long time. Even before the decline of the coal fields, these communities had relatively high rates of unemployment, and the loss of coal has left a large hole in the economy.

By the mid-1990s, as the scale of the economic degeneration became clear, the UK did institute some programs and policies to ease the transition, with varying degrees of success. The programs included regional and local regeneration projects, as well as economic and social support programs targeting individuals, community groups, and businesses. Unfortunately, they have mostly not achieved the desired socioeconomic outcomes.

The UK Climate Change Act, enacted in 2008, attempted to remediate some of these failures by taking a more comprehensive look at the clean energy transition. The Act was designed with a longer-term, more flexible planning outlook on worker training and re-skilling, regional economic development, and stakeholder engagement through just transition commissions and advisory groups.


The UK’s coal transition has been both rapid and strongly slanted toward renewables. Innovative policy levers helped to get the price right on coal production while catalyzing a nascent renewables industry, especially new offshore wind capabilities. Carbon pricing has emerged as perhaps the defining factor in pushing coal out, which is set to finally occur in 2024 if not before.

The UK’s historic coal communities, however, have borne the brunt of this transition. Critics feel the government acted too late to support workers and communities that were dependent on the coal value chain. Recent interventions seek to remedy the challenges they are facing, but a more managed approach may have prevented some of the economic hardships that remain today.

Kenya’s Growth through Clean Energy

This spotlight primarily advances the priority outcomes highlighted below. These outcomes are further described in the complementary Points of Progress report and in the Fossil Fuel Transition Strategies report.

Exhibit 1: Priority Outcomes for Global Energy Transformation

During COP26 in Glasgow, Kenya made the remarkable commitment to achieve a full clean energy transition by 2030. While ambitious, the pledge is not as implausible as it might be in other places. Kenya, in fact, has deployed significant amounts of clean resources in recent years, including hydroelectric, geothermal, wind, and solar generation, far outpacing investment in fossil fuels.

Importantly, Kenya also maintains a favorable economic and investment environment. GDP per capita has continued to grow year-on-year without any significant reliance on fossil fuel generation. By 2014, Kenya announced economic figures that qualified it as a middle-income country. The level of economic dynamism has attracted some of the biggest renewable investments in Africa, including the continent’s largest wind farm, the Lake Turkana Wind Power Project, and the world’s largest single geothermal plant, the Olkaria IV Geothermal Power Station.

These developments have helped Kenya expand electricity access from below 30 percent 10 years ago to well above 75 percent, a rate of expansion that dwarfs other nations at similar levels of development. As many countries in similar positions advocate the well-trodden path of fossil fuel–focused development, Kenya appears to have chosen a different approach.

I don’t know whether you can industrialise without carbon; history has shown us a carbon path. We are asking ourselves whether there is an alternative.

—Monica Juma, Kenya energy minister (Financial Times, May 2022)
  • Kenya and many other African countries are at the cusp of an important opportunity. Costs of renewable energy have plummeted. Clean energy technologies provide cheap, reliable — and, importantly, secure — energy resources for countries that are building out their energy infrastructure.
  • Increased investments in renewable developments are generating returns for these countries and investors, while avoiding the extraction of profits and rents that have plagued fossil fuel development globally.
  • Importantly, clean energy development is not just benefiting the rich or the urban. Kenya’s commitment to universal access underpins an electrification strategy that, since 2018, has increased access faster than anywhere else on the continent, through both on- and off-grid solutions.
Context on Kenya’s Growth

Emerging markets face an unprecedented opportunity, as technological advances make direct electrification through renewables among the lowest-cost and most efficient pathways for development, regardless of climate ambition. To date, Kenya has chosen to pursue this opportunity of electricity modernization through the development of clean generation, transmission, and expansion of electricity access, rather than following the route laid down by Western and developed countries seeking to expand fossil fuel markets.

Kenya has been endowed with high levels of renewable energy potential, which it has historically exploited through hydroelectric power. Geothermal power has also been on the rise since the first installation in 1981, and geothermal now accounts for around one-quarter of total installed electricity capacity, similar to hydro. This high level of renewable dispatchable power penetration has enabled effective system balancing of variable solar and wind generation resources.

Kenya has made notable progress in deploying clean energy in large part because it has successfully attracted the necessary private investment for renewable projects. Leadership has demonstrated commitment through its Vision 2030 strategy, which seeks to transform Kenya into an industrializing market through a series of governance changes and infrastructure investments. The government has also committed to expanding access by leveraging both utility-scale and distributed energy resource (DER) investments and last-mile connectivity, as outlined in its National Electrification Strategy.

To translate these policies into lower-risk investments, Kenya introduced a renewable energy feed-in tariff policy for small to medium projects, which guarantees a generator a predetermined tariff for 20 years. With the introduction of revised feed-in tariffs in 2012, Kenya was able to accelerate the energy expansion by creating more confidence for investors. Additionally, other policies such as VAT exemptions on clean energy equipment have lowered the capital expense of development.

Focus on Access

Kenya’s national development strategy, Vision 2030, seeks to make electricity access universal. Much of Kenya remains rural, where on-grid solutions are costly and logistically challenging. Private investment in off-grid solutions continues to grow through businesses such as M-Kopa, a low-cost-financing, pay-as-you-go residential solution. Since 2012, M-Kopa has installed over 215,000 off-grid solutions in Kenya, Uganda, and Tanzania. These solutions are important for driving early progress toward electricity access outcomes.

When I installed solar power into my home, I ended up making considerable savings from the use of kerosene lamp for lighting and charcoal in my house. Hospital bills for my family have since gone down, and we now have internet and watch international sports in my home.

—James Kariuki, resident of Nakuru County, Kenya (AP News, April 2022)

As a result of these off-grid projects, as well as more centralized solutions, Kenya has achieved over 75 percent access to electricity, which ranks among the best in Africa. This includes not only deploying minigrid and microgrid solutions, but also stimulating rural demand through productive use pilots.

Lastly, the Kenyan government and development banks have also pumped large amounts of money into expanding transmission to achieve universal access by 2026. A last-mile transmission scheme, funded by the African Development Bank (AfDB), launched in 2017 with the support of a $135 million loan. AfDB’s primary strategy focuses on the recognition that electricity supports job creation and entrepreneurship.

Multi-Tier Framework for Energy Access (MTF)

The World Bank–funded Energy Sector Management Assistance Program (ESMAP) launched the MTF initiative to recognize that electricity access is not homogeneous in terms of quality, affordability, and other factors. The methodology categorizes electricity access into different tiers, with 0 being the worst and 6 being the best, based on the following criteria: capacity, availability, reliability, quality, affordability, formality, and safety. Regular surveys provide the input data. Further information on the MTF is available in the report Points of Progress: An Introduction to RMI’s Global Energy Transformation Guide.

Kenya’s most recent assessment (published in 2020) puts all grid-connected households at tier 3 or above (meaning at least eight hours of service). More than a third of grid-connected households are tier 5 or above. Around 15 percent of the population now has either tier 1 or tier 2 access through off-grid solutions. For grid-connected customers not at tier 5 or above, reliability and quality are the biggest barriers. Payment flexibility to manage high up-front costs remains the biggest challenge for those seeking grid connection.

Investing in Kenya

Beyond access, Kenya is successfully attracting private and public investment, both domestically and from abroad, in its burgeoning renewables sector. Following a sharp reduction in the global economy in 2020 due to COVID-19, foreign direct investment rebounded in Kenya, underpinning new growth. The Economist Intelligence Unit summarizes succinctly, “Another key investment target is renewable energy, both grid-based and off-grid, underpinned by climate change imperatives. Conversely, investment in fossil fuels is becoming less appealing, raising doubts about the proposed exploitation of Kenya's oil reserves in Turkana County.”

Aside from the market signals Kenya’s policies and commitments have sent, academic studies highlight Kenya’s fiscal and macroeconomic environment as a driving force for renewable energy investment. This has opened up a significant opportunity for Kenyan workers. Analysis by IRENA and the AfDB indicates that a climate-aligned development scenario could almost triple the number of energy jobs in East Africa, from around 1.5 million in 2019 to 4.2 million by 2030.

While Kenya has invested heavily in transmission, last-mile connectivity, and rural minigrids, it is also looking to benefit from large-scale capital investments in other parts of the energy sector. For example, the Lake Turkana Wind Power (LTWP) Project, Kenya’s largest private investment so far and the largest wind farm on the continent, generates up to 310 MW at a cost of more than $600 million. The project developers claim that it employed more than 3,000 people during construction, 75 percent of them local to the area, and that it currently employs more than 300. The development included not only the wind farm, but also significant infrastructure upgrades to the local roads and commensurate community investments through philanthropic foundations. In all, the project is the largest public employer in the area and mitigates around 740,000 tons of CO2 equivalent per year.

Geothermal investments are seeing similar increases. The European Investment Bank (EIB) has loaned around €290 million into the sector over 40 years and sees geothermal as a strategic development investment sector. For example, the Olkaria Geothermal Power Plant Complex includes more than $1 billion in capital investment across multiple phases.

The result of this investment can be seen in the rapid expansion of installed capacity across Kenya. Kenya’s recently implemented Renewable Energy Auction Policy, which seeks to ensure renewable power projects are competitively procured at the lowest price, may shift the investment approaches more toward wind and solar in the future.

Importance of Managing Social Impacts of Large Capital Projects

Like many large capital projects across industries, the LTWP Project has had to manage significant social impacts. Because the project was financed externally, including originally from the World Bank, a number of environmental and social impact statements and studies are available to the public that document the social impact concerns of the project.

Perhaps most contentious was managing land acquisition, especially as much of the land in the area is informally titled. Local communities raised grievances against the LTWP over perceived land-grabbing, which culminated in a lawsuit that was ultimately dismissed. These complaints were accompanied by claims of improper community participation, as well as increased crime. Community members also highlighted that they were restricted from accessing land necessary to sustain livelihoods.

Negative impacts of project development, regardless of sector, affect everyday people. Renewable projects in Kenya have been the subject of multiple human rights complaints, and, as with project development in any sector, social impacts need to be managed more effectively.

At the national level, the scale of investment carries risks to electricity customers. The World Bank withdrew support from the project based on concerns that provisions of the project power purchase agreement would place undue burden on customers due to its take-or-pay structure. Kenyan customers are dealing with high prices, although the costs mainly appear to stem from challenges internal to Kenya Power. Still, projects like the LTWP will need to holistically assess and manage impacts to all stakeholders in a way that ensures benefits flow equitably to all.

…Access to electricity, first and foremost, is a right of every citizen, and it is therefore the duty of the government of Kenya to provide electricity to all.

—George Tarus, project manager, KPLC Last Mile Connectivity Project (AfDB, August 2021)
Creating Barriers for Fossil Fuels

Kenya’s growth in renewables and electricity may be creating investment barriers for fossil fuels as well. West of the LTWP Project, Tullow and Africa Oil found what they believed to be commercially exploitable quantities of oil in 2012. The region appeared to be dealing with the boom and bust of the commodity cycles even when no oil was flowing. Ten years after discovery, oil still has not come to fruition, and the project’s partners have run out of money. Even larger operators, such as Eni, have failed to find the right mix of projects and commercially viable quantities of oil, making the petroleum industry particularly unappealing.

A similar pattern emerged when Kenya explored developing its first coal plant, the Lamu Coal Power Station. In 2014, Kenya invited tenders for a new coal plant along the northeast coast, near the UNESCO World Heritage Site of old Lamu. The plan was contentious from the start, with many perceiving it to be a relief valve for China’s shrinking domestic coal industry that would provide very little value to Kenya relative to other investments.

Activists and civil society groups attempted to stop the project by organizing opposition, and they eventually took the developer, Amu Power, and the National Environment Management Authority to court in 2016. The National Environmental Tribunal ruled in 2019 that the environmental and social impact assessment was deficient and revoked the environmental permits. As a result, the Chinese-backed supporters withdrew financing, and the coal plant’s development effectively stalled.


Kenya’s particular focus on economic development is on the leading edge of African economies, especially in the electricity sector. Even with supporting policies and climate-forward ambitions, however, it is far from unique. East Africa, especially, faces similar challenges and opportunities. While Kenya owes much of its success to high levels of geothermal and dispatchable hydroelectric generation, the broader region has similar levels of geothermal and hydro potential, as well as reasonable solar and wind resources.

Still, Kenya faces a number of challenges, such as affordable access to finance, challenging supply chains and transportation logistics, and institutional capacity issues that make wholesale transformation difficult. The country also faces the social impacts that come with large project developments. As blended finance options — namely private equity partnerships supported by large development banks — become increasingly attractive, de-risked pipelines of projects are becoming the bigger bottleneck. As the Economist Intelligence Unit notes, “Africa’s appeal will continue to benefit from better rates of return than in more mature markets — albeit with more risks attached — as well as from population growth and regional integration.”

As such, renewables, along with other sectors, can underpin economic growth opportunities across African markets when the right supporting institutions are in place. In fact, Global Climatescope (by BloombergNEF), in its annual ranking of attractiveness to power market investment (transition tech), places Nigeria and South Africa in the top 10, alongside other hot spots such as India, China, and Vietnam. These types of climate-forward growth pathways give countries without a deeply entrenched fossil fuel sector a new option to secure economic development — without the need to clean up afterward.

Overcoming Long-Term Fossil Fuel Generation PPAs in Chile

This spotlight primarily advances the priority outcomes highlighted below. These outcomes are further described in the complementary Points of Progress report and in the Fossil Fuel Transition Strategies report.

Exhibit 1: Priority Outcomes for Global Energy Transformation

These long-term contracts have impeded us, in a way, from taking advantage of the drop in prices that a part of the market has had access to.

—Joaquin Villarino, Consejo Minero de Chile (BNAmericas, August 2020)

Chile is the world’s largest copper producer, accounting for around 30 percent of global production. Copper mines consume a significant portion of Chile’s electricity at around 25 TWh annually, or 34 to 37 percent of total generation. The national grid generally supplies electricity to the copper mines, which shore up their supply via direct power purchase agreements (PPAs) with independent power producers (IPPs) who provide additional generation.

Energy makes up a significant portion of a mine’s operating expenses. During the early 2000s, high energy prices and insecure resources caused many mines in Chile to sign coal PPAs in order to secure cheap, reliable supplies of electricity. Since then, the falling cost of energy due to the expansion of renewables has incentivized many mining companies to reevaluate their power supply contracts.

As the Chilean government seeks to phase out coal, and as new renewable energy projects drastically lower the market costs of power, IPPs are looking for novel ways to reduce their coal exposure and avoid dealing with costly stranded assets.

Importantly, long-term PPAs provide IPPs the stability required to attract a reasonable cost of capital for reinvestment in cleaner energy. Therefore, while IPPs benefit from moving away from coal, maintaining PPA terms are important. This contrasts with the economic realities of mines, some of which have found it more cost-advantageous to simply pay out their PPAs, even at high cost, than to allow them to continue to term.

The independent power producer Engie Energía Chile S.A. (EECL), in particular, has made strides to transition more than 75 percent of its unregulated long-term PPAs to “green PPAs,” which are indexed to the US Consumer Price Index rather than coal, and which leverage renewable energy supplies. Through renegotiation of existing coal PPAs, EECL has secured the necessary long-term stability to manage its generation transition while bringing cleaner, lower-cost electricity to customers.

  • Long-term PPAs are one of the most intractable challenges in global coal, locking in companies and buyers even when the economics no longer make sense. EECL’s experience demonstrates that market-based solutions can yield win-win-win outcomes for buyers, generators, and the climate.
  • Removal of coal price indexing has allowed PPAs to gradually phase out coal, relieving IPPs like EECL of burdensome debt loads and ensuring the necessary certainty to invest in new renewable projects.
  • Investments in national transmission integration, coupled with (nonsubsidized) renewables-friendly policies, helped to expand low-cost generation from wind and solar in Chile, which drove down wholesale prices, making coal economically unattractive.
Evolution of the Chilean Electricity System

Chile’s electricity system is fully privatized and operates in three segments: generation, transmission, and distribution. Between 1990 and 2018, increasing economic development caused electricity consumption in Chile to grow a staggering 460 percent. Starting in the 1990s, Chile began importing natural gas from Argentina, displacing some historic coal plants and lowering the cost of electricity. Due to domestic shortages, however, Argentina began curtailing gas exports and by 2007 had essentially stopped exporting. In response, Chile rapidly increased the deployment of coal generation units to handle rising demand, with much of the activity driven by mining companies securing future supplies in light of rising prices.

Two major occurrences helped change the market in Chile, however. In 2013, the country enacted a new renewables feed-in obligation. This spurred development of new wind and solar capacity, especially in the north of Chile, leading to a massive reduction in power prices (as well as a new market in renewable energy certificates). The falling cost of renewables primarily drove the reduction in power prices, supported by policy and tendering approaches, such as a transmission-tariff relief and novel hourly-time blocks in technology-neutral supply auctions. (For more on Chilean auctions, see the Fossil Fuel Transition Strategies report.) Exhibit 2 shows the effects of 2015’s hourly-time block supply auction reforms on award prices for countrywide generation bids.

The second major factor was the creation of the National Electricity System (Sistema Eléctrico Nacional) in 2017 when the Greater Northern Interconnected Grid (Sistema Interconectado Norte Grande) was linked with the Central Interconnected System (Sistema Interconectado Central). This allowed the national grid to optimize the deployment of renewable capacity across most of the country. Upgrades to the unified system (which covers around 99 percent of the country) have driven wholesale prices lower and allowed for lower-cost renewables in the north to be sold throughout the market.

Long-Term Coal PPAs

Coal power plants are expensive to build and operate. Long-term PPAs are needed to ensure a proper return for developers but have locked buyers like companies, utilities, and municipalities into contractually obligated purchases, even when the PPAs no longer make economic sense. In addition, the price of power in these PPAs is often directly linked to the cost of purchasing coal — a practice known as coal price indexing that can expose buyers to volatile coal markets.

The deployment of appropriate regulatory and financial mechanisms to drive the early or accelerated transition of coal assets, while protecting customers and taxpayers from excessive costs, has proven successful in some contexts. However, termination of coal PPAs to drive early closure is still an evolving practice. Financial mechanisms used to close plants to date have focused on complex securitization arrangements or novel transition funds that draw from public or concessionary finance. EECL’s experience focuses on taking advantage of falling renewable prices to modify commercial terms of the PPAs and produce wins for both EECL and the buyers.

Engie Reevaluates Contract Structures

In 2019, Chile made the ambitious commitment to phase out coal, starting with a first phase binding large producers, including EECL, to close or transition their coal assets by 2024. Meanwhile, falling costs of wholesale power had caused many copper mines to reevaluate their long-term PPAs to reduce overall costs. These pressures from both sides placed generators in the precarious position of needing to rapidly transition expensive coal assets while expanding the base of new, cleaner generation.

EECL, for example, plans to close or convert all of its coal power plants by 2025, amounting to some 1.5 GW of transitioning coal production, even while growing overall generation by 1.5 GW. Engie estimates this will require an investment of nearly $200 million in 2022 for new projects and acquisitions, as well as $1.3 billion between 2023 and 2026.

To develop these resources, as well as transition coal, EECL has secured financing through two main avenues. The first is a novel financing instrument through the Inter-American Development Bank (IDB) to monetize coal emissions reductions through a new wind farm development (see “Investing in Reversing” box). The second is through private financing. From public disclosures, it is unclear if EECL uses project financing or revenues from the balance sheet to fund renewable projects. In either case, long-term PPAs help secure the needed revenue to support continued expansion.

Investing in Reversing

As part of IDB’s “Investing in Reversing” initiative, EECL and IDB are piloting a novel financing scheme to support coal retirement and new renewable generation. The pilot will provide $125 million in financing to support a 151 MW wind farm. The financing package is jointly funded by IDB, China Fund for Co-financing in Latin America and the Caribbean (an IDB-administered cofinancing fund from China for infrastructure projects), and a blended finance instrument called the Clean Technology Fund.

The financing mechanism will price the avoided greenhouse gas emissions for early retirement of EECL’s coal assets as a result of the new wind farm and apply these “offsets” to commensurately reduce the interest payments on the Clean Technology Fund loan. This provides a financial incentive for EECL in lieu of a carbon market. The pilot is still in its nascent phase, but if it succeeds, it could be scaled to support the phase out of 8,000 MW of coal and oil generation Chile has committed to end, with even greater potential in the wider region.

Because of these incentives to maintain PPAs, EECL has renegotiated long-term coal-indexed PPAs amounting to around 75 percent of its unregulated (non-distribution utility) portfolio. EECL’s novel approach involves reducing the price of coal indexing, followed by the redeployment of new “green PPAs” that rely on clean energy. This lowers overall costs to customers, while ensuring investor certainty to enable Engie to access capital and financing to invest in new renewables.

EECL’s PPA Renegotiation with Antofagasta Minerals

One of EECL’s successful PPA renegotiations was the recent signing of a new green PPA to support mines operated by Chilean corporation Antofagasta Minerals (AMSA). The original PPA between EECL and AMSA had brought the coal plant Central Termoeléctrica Hornitos (CTH) on line in 2011, with the plant operating as a joint venture through a special purpose vehicle (SPV) owned by EECL and a subsidiary of AMSA.

Starting in 2018, AMSA and EECL began discussions to reevaluate the terms of the PPA, given falling prices in the wholesale market. By 2020, they finalized an agreement whereby EECL would purchase the remaining stake of CTH, pay down debts on the plant, and lower prices on the coal-indexed PPA, whose date of maturity was moved forward to the end of 2021.

In exchange, AMSA signed a new green PPA with EECL, with tariffs indexed against the US Consumer Price Index (CPI), a measure of inflation, for the remainder of the term of the original coal PPA. The PPA was also extended into a second phase with prices discounted further for AMSA. The longer duration of the PPA provides EECL with greater revenue certainty and allows it to further reinvest in new renewables. Finally, while the terms of the PPAs have not been made public, regulatory filings suggest that AMSA may have made a one-time payment to finalize the renegotiation of the PPAs and offset initial costs for EECL.


Chile has made remarkable steps in decarbonizing its electricity system, which generates 32% of the country’s emissions. It is anticipated that 18 of its 28 coal plants will be phased out by 2025. Three have so far been retired in 2022, earlier than anticipated.

EECL’s change in portfolio is anticipated to close 800 MW of coal and see a further 700 MW of coal converted to biomass. New financing mechanisms being piloted by IDB may accelerate this process. EECL is anticipating an 80 percent reduction in net emissions by 2026, in part by eliminating coal from its portfolio.

As the world seeks to transition away from coal, new approaches are needed to ensure a timely, affordable phaseout of coal generation. Taking advantage of lower wholesale prices gives large buyers leverage to reevaluate procurement processes for energy contracts. Chile’s strong policy signals helped create regulatory certainty for the market, which is dominated by a small number of key players in the generation sector. These new PPAs provided long-term revenue and certainty to underpin financing, and they allowed IPPs to maintain existing business relationships while reducing emissions and costs. Coal plant owners also benefit, as these proceeds are reinvested into lower-cost, higher-profit renewable generation. The end results support both business and climate outcomes.

Stakeholder-Driven Just Transition in Canada and Germany

This spotlight primarily advances the priority outcomes highlighted below. These outcomes are further described in the complementary Points of Progress report and in the Fossil Fuel Transition Strategies report.

Exhibit 1: Priority Outcomes for Global Energy Transformation

As COP26 in Glasgow came to a close, most advanced economies made commitments to phase out coal entirely by the 2030s. While COP26 may not have marked the “end of coal” as organizers had hoped, it was successful in recognizing the varying levels of commitment and ambition of coal phaseout.

As countries look at moving away from coal, they must plan carefully to ensure that communities and workers that depend on fossil fuel value chains are supported during the transition. The transition away from legacy assets poses significant risks to these communities, including job loss, reduced property value, reduced tax revenue, remediation and cleanup liabilities, and increased uncertainty for economic development.

In the cases of Canada and Germany, coal development has been concentrated in areas far from the centers of power that are economically disadvantaged. The unmanaged loss of the coal industry would devastate their local economies. As such, both countries took a largely stakeholder-driven approach to identify pathways for a just transition. Whereas Canada primarily focused on actions at the local level, Germany’s approach was more expansive.

  • Just transition planning takes a long time. Germany’s current ambitions will phase out coal by 2038 or before, while Canada is targeting 2030, which is significantly faster than the just transition experiences of “model” regions like Germany’s Ruhr Valley .
  • Impacted workers and communities need to be at the heart of transition planning. Coal commissions brought together diverse stakeholders whose work in impacted communities helped to legitimize recommendations to government.
  • Stakeholder commissions can bring a variety of recommendations, but it takes institutional action to cement those into policy. Funding and government support will be critical to ensure words turn into actions.
Context on Coal and Transition Commitments in Canada

Canada has had commercial coal mines since at least the 1700s. But oil and gas play a larger role today, as Canada’s coal industry has largely declined in recent decades.

In 2005, about 16 percent of Canada’s electricity came from coal generation. In 2016, after Ontario closed its coal-fired generation, that share fell to 9 percent. The national government committed in 2012 to coal phaseout by 2061, although just transition considerations were not included.

In 2018, as part of Canada’s decision to accelerate coal phaseout by 2030, the government established the Task Force on Just Transition for Canadian Coal and Power Workers and Communities. This committee was intended to allow diverse stakeholders to assemble and create proposals to support workers and communities during the transition.

At the time, the industry employed an estimated 11,000 people, concentrated in the five provinces that hosted Canada’s 36 then-operational coal plants. Today, only 21 units remain in operation, and six of those may close by 2023 under Alberta’s phaseout commitments.

Coal mining is on a similar trajectory: 17 mines were open at the start of the process, but 4 have already been closed or mothballed due to declining local demand. One new mine, in Alberta, opened in 2019. Canada lacks a unified mine closure framework, which poses a notable challenge. Closure and remediation are handled at the provincial level and mainly local officials have the discretion to approve plans and progress.

Context on Coal and Transition Commitments in Germany

Germany’s coal transition, and especially its experience with just transitions, can largely be separated into two developments. The first is the formation of a national-level coal transition task force that currently focuses on closing coal plants and transitioning lignite coal mining communities. The second is the regional redevelopment of the Ruhr Valley and Saar region, which focused on hard coal mining.

Unlike in Canada, coal has historically played a major economic role in Germany, where the hard coal mining industry employed more than 600,000 people at its peak, and the transition has been taking place for 60 years.

Germany’s transition experience in the Ruhr Valley, a heavily urbanized and industrialized region, dates to the 1970s. During the 1980s, the region experienced high unemployment due to a series of macroeconomic shocks to the coal and steel industries. Initially, policymakers responded with a string of industry subsidies, but through the 1990s the policy aim shifted to redevelopment at the grassroots level. By 2018, the last hard coal mine in the Ruhr Valley closed permanently. The transition occurred slowly enough to allow the region to develop significantly and thus diversify, although many challenges remain from mining’s legacy.

Lignite coal also plays a role in the broader German energy sector. Since 2000, however, Germany has undertaken a policy of Energiewende (energy transition), a broad set of energy policies aimed at supporting a clean energy transition. The Energiewende helped increase renewable energy sources from 3 percent of electricity in 1990 to around 45 percent in 2020, along with creating an estimated 350,000 jobs. Still, lignite makes up a large portion of Germany’s power mix and continues to challenge emissions targets.

As the broader social narrative around coal has changed, Germany has taken greater action in transitioning lignite mining and coal generation plants as well. Following reunification, Germany took steps to exit Eastern lignite fields, but now the industry is facing its final strides. Similar to Canada, Germany established the Commission on Growth, Structural Change, and Employment (known informally as the German Coal Commission) in 2018. This brought together a series of affected parties, trade union representatives, NGOs, scientists, and citizens to advise the German government on transition strategies. The coal commission has provided recommendations to ensure coal workers and their communities are supported, as well as a target closure date of 2038 (although this target may move up).

At the time of the commission’s work, Germany had 111 operating lignite and hard coal power plants, totaling around 44 GW in capacity. Despite declining coal production, Germany still has around 98 operating coal units, a figure that has ceased declining in the past year as 21 coal plants have been allowed to work past scheduled closures or reopen in light of Europe’s ongoing energy crisis.

Finally, in contrast to Canada, Germany has fairly strong regulations in terms of mine closure and remediation, which include socioeconomic as well as technical aspects. Former mining areas in Germany now feature industrial wildlife parks and lake resorts, bolstering local economies and well-being.

Stakeholder Commissions in Canada and Germany

Canada’s Task Force on Just Transition for Canadian Coal Power Workers and Communities had a relatively narrow mandate: “recommendations for how to support a just and fair transition for Canadian coal communities and workers, as Canada has committed to stop generating traditional coal-powered electricity by 2030.”

The task force consisted of 11 individuals representing labor unions, the coal industry (mining and generation), trade groups, municipalities, an environmental NGO, the power industry, and academia. Through a series of site visits, interviews with stakeholders, and public meetings, the task force synthesized findings into a report delivered to the minister of the environment and climate change in 2019.

The report comprised 10 key recommendations, which are summarized in Exhibit 2.

As a result of the recommendations, Canada initially pledged around CA$35 million in support of just transition programs. These include worker transition centers and other community-driven projects. Canada also announced a dedicated infrastructure fund of about CA$150 million to support infrastructure projects and economic diversification investments in impacted coal communities. These projects have included support for economic development strategic plans, land use and infrastructure services, direct worker support, support for business centers, and other community-oriented projects and studies.

The recommendations from the task force have enjoyed broad support, and the government of Canada has issued early, though limited, funding to support the initiatives. The report itself concluded that the transition will cost “well into the hundreds of millions of dollars” and will extend past the 2030 phaseout targets. Canadian think tanks place transition costs much higher, well into the billions of dollars per year. The lack of action by Canada’s government to enshrine some of these recommendations into legislation has become a source of satire, with environmental advocates lampooning policymakers in statements from a fictitious “Ministry of Just Transition.”

In 2018, Germany convened a similar but larger group of representatives in the German Coal Commission, totaling around 31 members. The commission’s mandate was somewhat broader than in Canada, opining on coal phaseout dates as well as national policy related to the phaseout (in addition to local-level recommendations). The commission is rooted in Germany’s nuclear experience, in particular a 2016 report by Agora Energiewende that called for a body to build a national social consensus on coal. Following that report, Germany’s Climate Action Plan 2050 officially included a commitment to convene a commission to “develop realistic prospects for the industries and regions affected, to agree on the resulting implementation strategies, and to create the necessary financial conditions.”

As in Canada, the commission conducted expert interviews, stakeholder sessions, and regional site visits in order to formulate conclusions about the need for just transition support at the local level. Importantly, the commission was also tasked with suggesting a trajectory for the phaseout, which was projected to affect around 20,000 jobs.

The commission’s 2019 report recommended full coal phaseout by 2038, as well as a host of just transition support programs. Recognizing the investment horizons in the energy sector, Germany’s pathway is a gentle phaseout. The commission recommended around €2 billion per year in energy assistance to deal with rising prices, compensation to coal plant owners, and hundreds of potential projects. Most importantly, it highlighted the need for around €40 billion in investment over a 20-year period, which is detailed in a transition law.

The transition law, as well as a separate coal exit law, helped to enshrine the recommendations from the commission into government policy. The law allows for two broad buckets of funding through 2038. About €26 billion is set aside for federal use, focusing on agency funding or job creation. Another €14 billion is earmarked to support lignite-mining regions across four states. The law allocates another €1.09 billion toward hard coal mining areas, totaling €41.09 billion in just transition funding.

This funding will support projects at the local level, including new infrastructure and environmental protection work. Because of the gradual nature of the coal exit, many workers will likely be near retirement age by 2038, so the law makes provisions to support them financially between phaseout and retirement as well. The laws did not include certain recommendations, such as targeted education, retraining, and lost-wage compensation mechanisms.

Currently, the government is attempting to accelerate the closure date to 2030, which is causing tensions with stakeholders who already found 2038 difficult. This acceleration effort may be derailed anyway due to energy uncertainty as a result of Russia’s invasion of Ukraine. Germany also has committed around $180 billion to support clean energy investments through 2026, including in energy efficiency, hydrogen, and vehicle electrification.


Canada and Germany both leveraged commissions to help understand and influence national policy by aligning it with local impacts and expectations.

In Canada, the commission had a fairly narrow mandate, focused on local impacts and transition requirements. Germany’s commission had a more holistic directive, seeking to build a societal consensus on the future of coal. In both cases, the commissions represented diverse stakeholders and in turn evaluated just transition considerations from a variety of viewpoints, which helped build legitimacy in the resulting outcomes. In Germany, this took the form of new laws and significant state investment. While Canada has yet to enact legislation beyond its first commitments, a potential just transition act enjoys broad popular support.

Including relevant stakeholders in a participatory institution provides legitimacy and ownership for the managed transition.

—Alexander Reitzenstein and Rebekka Popp, German Coal Commission (E3G, April 2019)

Although there are several notable aspects of the just transition efforts in Canada and Germany, critics have raised concerns about both processes. In Canada’s case, there is a major concern with lack of long-term commitment, both in terms of funding and government policy. In some cases, more sustained action is occurring at the provincial level, such as in Alberta, but this predates work by the Canadian task force. In Germany’s case, the amount of compensation required and the duration of the transition make the process very expensive, perhaps pricing many countries out of this pathway. The long-term duration also makes Germany less able to adapt to changing circumstances, such as the Russian invasion of Ukraine or shifting EU policies like Fit for 55 .

Going forward, countries looking to transition their fossil fuel industries can learn a number of key lessons. These countries can first acknowledge the adverse effects that could occur during a transition, and how these will be shared unequally across sectors, geographies, and socioeconomic groups. Incorporating diverse viewpoints from the local level, as well as industry and society viewpoints, helps identify the impact that national actions may have on workers and communities. Countries will need to carefully consider the mandates of these commissions or stakeholder engagement activities to ensure they align with needs and expectations. The right mandate and set of participants will help legitimize the resulting recommendations.

Germany’s Ruhr Valley experience is seen largely as a best practice in economic diversification away from coal. This paper will largely focus on Germany’s just transition in the lignite mining areas, but a comprehensive overview of Ruhr Valley’s Just Transition experience is available here.
This section has not been endorsed by EECL or any of its partners. This description is based on a synthesis of public statements, regulatory filings, investor presentations, and discussions with individuals knowledgeable about the Chilean energy sector. Sources: 1Q2020 Investor Presentation, 4Q21 Press ReleaseEECL Hornitos Plant Press Release, S&P Global: Chile Speeds Up Plans, EECL 3Q21 Investor Presentation, EECL 1Q2021 Investor Presentation, EECL 3Q2021 Press Release, Chilean Ministry of Energy Plan of Phase-out and/or Reconversion of Coal Units, and SEC Regulatory Filings.