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.

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.

Insights

• 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.

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.

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.

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.

Conclusion

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.

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.

Insights

• 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.

Conclusion

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.

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.

Insights

• 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 350.org 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.

Conclusion

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.

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.