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Business Models for Transition of Coal Generating Capacity
Sandhya Srinivasan, Debabrata Chattopadhyay, Chandrasekar Govindarajalu, Izzati Zabidin
1
World Bank
June 2022
Abstract:
Coal-fired electricity generation accounts for more than 10 Gt, or roughly 30 percent, of global CO2
emissions, with the majority of coal-fired generation capacity located in developing countries. It is
possible to significantly reduce emissions from older, expensive and inefficient coal plants at less than
US$10/tCO2e. However, in the absence of suitable business models and financing options, accelerated
coal decommissioning may not transpire. The paper is intended to inform discussions on accelerating
coal transition in a financially and technologically sustainable manner by collating experiences with
recent and ongoing global efforts toward coal plant retirement. This paper discusses the experience
with different approaches thus far and their potential merits and drawbacks.
1
The team thanks Stephanie Rogers and Marlen Goerner for their inputs as well as our colleagues Xiaodong Wang,
Fred Verdol and Satheesh Kumar Sundararajan, who kindly reviewed an earlier draft of this paper. The opinions
and views presented in this article are the authors’ own and do not necessarily represent the views of the
International Bank for Reconstruction and Development/World Bank or its affiliated organizations.
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1. Introduction
The global stock of operating coal power plants stands at nearly 2,100 gigawatt (GW) (GEM, 2021) and
accounted for 30 percent of global CO2 emissions (IEA, 2019). Since 2000, total installed coal capacity has
increased by 62 percent, with as many as 14 countries beginning to use coal for power generation for the
first time during this period. A significant part of the global coal capacity is, therefore, relatively new.
Considering the long operating life of coal plants, this poses a serious challenge for low carbon transition.
Emissions from coal plants built up to 2016 are estimated to contribute 200 GtCO2, and a further 100 -150
GtCO2 is expected from coal plants under construction (IPCC, 2018). Committed fossil fuel emissions
already amount to over two-thirds of the remaining carbon budget.
Two-fifths of the world’s coal power stations are already running at a loss (Carbon Tracker, 2018).
Estimates for the global stranded asset costs associated with coal plants range from a quarter of a trillion
dollars by 2030 to a trillion dollars by 2040 (RMI, 2018; World Bank, mimeo). The existence of long-term
financial contracts, such as power purchase agreements (PPAs), may set the level of compensation to
owners well above the stranded capital costs of the plant. Beyond compensation costs to owners for
forgone profits from early retirement of coal plants, there is a range of additional costs associated with
coal transition. These include inter alia the cost of environmental remediation upon accelerated coal plant
decommissioning, and the social costs associated with retraining or re-skilling workers and communities
that depend on the coal plants (or associated coal mines) for livelihood. Furthermore, there may be wider
social costs, such as indirect job losses at ancillary businesses associated with the plant, or upstream
impacts on the mining sector, requiring a comprehensive strategy for just transition (World Bank, 2018).
There are successful examples of coal transition emerging, most notably in the UK and Europe, where
there are examples of coal plants that have been shut down well ahead of their economic life. Old coal
plants are also being shut down in other parts of the world at a faster pace than ever. However, the
achievement of 1.5°C requires far greater acceleration of coal plant closure at the global scale. For
developing countries, the question of coal transition is accompanied by the added challenge of meeting
rapidly growing electricity demand, and the investments needed in alternative energy to replace the
electricity supply and ancillary services provided by the coal plants.
A planned transition can offer countries an opportunity to replace the electricity supply from retired coal
plants, perform the necessary upgrades to the power system to successfully integrate a higher proportion
of renewable energy (RE), and ensure a just social transition. This paper focuses on the ageing, expensive
and polluting fleet of coal plants, and potential business models that can be adopted for efficient
acceleration of the process of shutting down coal plants.
This also raises the question of concomitant changes needed in the upstream mining sector. While
addressing the question of coal mine closure in conjunction with coal plant retirement would likely
broaden the scope and support a more inclusive transition, the complexities associated with coal mine
closure would require a more comprehensive discussion than the issues considered in this paper.
2. Opportunities and Challenges
Since 2010, installed coal plant capacity has nearly doubled in China and India. However, there has also
been a significant drop in the utilization of the older coal fleet, which presents an opportunity for
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accelerated retirement and repurposing. At the same time, the levelized cost of electricity (LCOE) for
renewables has seen dramatic declines over the past few years and is, in fact, lower than the cost of
conventional fossil fuel generation in many countries.
One of the core technology challenges associated with coal transition is the cost of integration of variable
renewable energy (VRE) in the power system. Solar and wind energy are “non-synchronous” and typically
do not provide inertia or many of the other ancillary services. In fact, they may significantly increase the
need for such services since they increase the level of contingency reserve needed by the system, as well
as the need for flexible resources to ramp up generation elsewhere to compensate for their variability
(Perez-Arriaga and Batlle, 2012).
Therefore, the performance of power systems after the retirement of a substantial portion of the coal
fleet presents a technological conundrum. Some authors have argued that the cost of renewable
integration is very small (less than US$c1/kWh) and is not unique to VRE (NREL, 2004). However, other
sources suggest that integration costs may be significant. Agora (2015) estimated the integration costs of
German onshore wind and solar power, including the costs of grid reinforcement and balancing, at €c 0.15
– 1.2/kWh, and an additional cost of up to €c 1.0/kWh for costs imposed on the conventional generation
fleet to provide backup capacity and wear and tear of load following generators. Pudjianto et al. (2013)
estimated the integration costs of solar PV for Europe to lie between €c 0.5 – 2.5 /kWh. Debnath et al.
(2021) showed that an increase in VRE generation leads to increased wear and tear of the existing coal
fleet due to partial load operation, and that VRE integration costs at the upper end can be as high as US$c
5/kWh, effectively representing a doubling of the current level of LCOE.
A reduction in coal capacity and associated grid services including inertia, frequency and voltage control,
accompanied by an increase in the demand for such services due to the variability of renewable electricity,
could make the grid vulnerable and increase proneness to failure. Even robust systems, that transitioned
quickly without fully addressing technological issues, experienced failures. For example, South Australia
reduced its coal capacity while wind capacity increased rapidly. It suffered a series of three grid failures,
including one in September 2016 during a storm that impacted transmission lines and caused a large
proportion of the wind turbines to be shut down. This led to a collapse of the grid, affecting 850,000
customers (AEMO, 2017). Following this event, Australia installed 100 MW/129 MWh battery energy
storage systems (BESS) to provide frequency control services. Similar incidents in the UK (2019) and Texas
(2021) serve to illustrate the vulnerability of power systems when common mode failure of VRE coincides
with an extreme weather event in the absence of adequate replacement or backup power. The need for
operational flexibility (i.e., frequency and voltage control ancillary services requirements) also increases
appreciably as the capacity and generation mix of a grid change from coal to VRE. A key challenge would
therefore be to find a way to reduce the cost of these services.
Several concepts have emerged over the past five years, such as virtual power plants, grid-forming
inverters and grid-scale BESS, that could partially address such concerns, but such solutions remain
expensive. Downstream investment financing support could be provided for coal transition under climate
finance programs such as the Climate Investment Fund’s (CIF) Accelerating Coal Transition (ACT) program.
Service providers are emerging to help manage aspects of coal transition. For example, Environmental
Risk Transfer (ERT) contract offers turnkey management of the site of coal plants, covering the full range
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of services from site purchase to closure, including due diligence prior to legal transfer, demolition
services to dismantle power plant structures, asbestos abatement, site remediation, marketing of coal
combustion products to minimize long-term on-site storage, and assessment of site redevelopment
potential. ERT offers an opportunity to transfer environmental liabilities to a third party through a
purchase/sale agreement for a service fee.
The choice of a suitable business model depends on a variety of factors and requires a detailed
examination of the incentives for different stakeholders. Several factors could impact the perceived risk
of stranding for coal assets, the expected level of compensation for asset owners or PPA holders, and the
availability of alternative sources of supply to replace coal capacity. This could include, for example, the
power market design, including the duration of PPAs and potential buyout or renegotiation provisions,
the costs paid by distribution companies and their financial strength, power dispatch decisions, the
existence of short-term power trading markets, the categories of consumers, and the incentives offered
for RE development. A fuller exploration of the interaction among a myriad of such variables and the
choice of business model would require substantial effort over the coming years. Nevertheless, in the
remainder of this paper, we have collated current discussions around plausible models and create a
typology to aid future discussions.
3. Business Models
This section focuses on different “business models”, or the set of options available for accelerated
decommissioning of coal-based power plants in a technically and financially sustainable manner that are
being tried, tested and discussed in different countries. The subsequent section discusses options for
financing such actions.
3. 1 Policy-based closure
Policy-based closure refers to a policy commitment or the introduction of legislation that phases out coal
plants directly (e.g., through carbon policies), or indirectly through policies on air pollution, introduction
of wholesale electricity market and reform of coal PPAs. Policy-based closure may not necessarily
constitute a business model per se but is an important enabling factor that provides the necessary
incentive for the accelerated retirement of coal plants. The existence of a credible commitment by the
governments to transition away from coal can play a significant role in the choice and feasibility of
different business models.
The introduction of a wholesale electricity market in the nineties together with the advent of gas as a
competitive alternative saw a steady closure of coal plants as they became older, inefficient and
uncompetitive. In 2017, the UK indicated that it would regulate the closure of unabated coal power
generation units by October 2025 by banning electricity generation from units which emit more than 450g
of CO2 per kWh. In 2020, the deadline was brought forward by a year to October 2024. The UK holds four-
year ahead Capacity Market auctions to secure electricity capacity to manage peaks in demand. The
introduction of emission limits to the Capacity Market coupled with stringent air pollution standards now
prevents participation by coal plants in these auctions (BEIS UK, 2021).
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In 2011, the Chilean Ministry of Environment instituted caps on power plant emissions of mercury,
particulate matter, sulfur dioxide, and nitrogen oxide, and indicated that these caps would become more
stringent with time. The intention was to force power plant owners to consider abatement technologies
or decommissioning. In 2019, the Government of Chile banned the installation and operation of coal
plants by 2040, which was later accelerated to 2038. In 2021, it announced plans to accelerate coal phase
out by retiring half of its fleet by 2025. The policy decision has been accompanied by efforts to encourage
asset rotation by coal plant owners to switch from coal to renewables. Chile has also introduced a
mechanism for placing coal plants as back-up reserve, whereby they would continue to receive
compensatory payments from the government for five years (Agora, 2021).
In 2021, under a new coalition agreement, the Government of Germany accelerated coal phase-out to
2030 from 2038. The plan included compensation arrangements for existing operators and economic
support packages for coal regions of about €40 billion. The law also proposes annual compensation for
additional electricity costs for energy-intensive companies from 2023 to ensure their international
competitiveness. Germany holds some hard-coal plants as “grid reserve” to manage potential supply
challenges, maintain voltage, or restore power after a blackout.
However, it could be challenging for rapidly growing coal dependent countries to provide strong policy
mandates for coal plant closure particularly in light of the energy security considerations that have
increased due to the ongoing Russia-Ukraine conflict. Nevertheless, a longer term policy objective to
move towards wholesale electricity markets can drive market driven natural attrition and help accelerate
coal power plant closures.
3.2 Buyout
Buyout refers to outright purchase of the coal asset from its current owner. The new owner of the coal
plant may decommission the plant, place it in reserve status, or operate it at a reduced capacity until
alternative sources of electricity supply are able to service the needs of the grid.
3.2.1 Reduced operations
One of the business models that could be applied to accelerate and facilitate coal plant closures is the
purchase of coal plants, which would then be operated at a reduced capacity rating before their eventual
planned retirement. The level of reduced operation would depend on technical considerations, such as
the level of supply and ancillary services required by the grid, as well as financial considerations, such as
the minimum level of operation needed to cover fixed costs and repayments to investors and lenders
before the plant is retired.
An application of this model is the proposed Carbon Reduction Facility (CRF) of the Asian Development
Bank’s (ADB) proposed Energy Transition Mechanism (ETM). The ETM is proposed as a national-level
mechanism consisting of (i) a CRF or ‘bad bank’ to acquire existing coal plants, operate them at a
significantly reduced plant load factor, and retire them in 10 – 15 years, representing accelerated
retirement against the plants’ planned lifetime of 30-40 years; and (ii) a Clean Energy Facility (CEF) to
provide technical assistance and financing to accelerate the development and deployment of RE sources.
Investors in the ETM would receive returns from both CRF and CEF instruments. The potential investors
in the ETM include Multilateral Development Banks (MDBs), who may contribute concessional finance or
support a blended finance mechanism by creating first loss guarantees; and private sector institutional
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investors and other long-term investors with low cost of funds. ADB’s ETM is initially expected to focus on
accelerated coal transition in the Philippines, Vietnam and Indonesia. (ADB, 2021).
The ETM could potentially attract existing owners, often state-owned power companies, that recognize
the risk of stranding to transfer their assets to the CRF in exchange for cash and, potentially, equity interest
in the ETM, with the expectation that the coal asset owners will invest the cash received from the CRF in
RE, grid upgrades, and activities that support a just transition for workers and communities. In parallel,
the CEF would provide finance and technical assistance for accelerated RE deployment and storage.
There are several country-level factors that could impact the implementation of the ETM. First, in cases
where the country has a high level of dependence on coal, ensuring reduced emissions can be challenging.
Second, determining the appropriate level of compensation to owners of coal plants would also be
challenging. Third, robust and enforceable agreements among relevant national authorities and MDBs
would be required to ensure that the commitments made under ETM are met. At the mechanism level,
the availability of funds at a sufficient level of concessionality to absorb all the costs of coal transition may
be the biggest challenge, especially for younger 10-15 years old plants. Finally, the model also needs to
address social protection, reskilling/retraining of any laid-off workers.
3.2.2 Shut down
This asset-level mechanism involves the provision of payments to existing coal asset owners/equity
holders as compensation to shut down the plants. Some of the enabling conditions for this model include
the availability of cheaper or affordable capital to transact coal plant buyouts, as well as the existence of
designated entities or institutions to execute the buyout, and monitor and oversee the process of shutting
down the plants. In a takeover and write-off arrangement, an entity (for example, the state or a parent
company) provides payments and takes ownership of a coal generation asset, which effectively transfers
any value to be written off from the original owner to the new owner.
While this model has the potential to accelerate coal decommissioning, there are significant issues related
to grid reliability and compensation costs payable over and above decommissioning and social costs. One
of the key considerations of the buyout model is the capacity and incentives for the new owner to retire
the coal plant. The buyer may also be concerned about reputational and operational risks associated with
owning the plant, and the associated environmental liabilities.
An example of the application of this business model is in the case of Florida Power & Light Company
(FPL). Between 2015 and 2017, FPL announced plans to purchase and retire two coal-fired plants, Cedar
Bay and Indiantown, with a combined capacity of over 1,800 MW. The plants were owned by separate
companies that supplied electricity to FPL under long-term contracts. The contracted electricity prices
were competitive when the long-term contracts were signed. However, by 2015, FPL was able to purchase
or generate electricity from other sources at lower prices. FPL determined that it would be less expensive
to purchase and retire the plants than to continue buying the contracted electricity supply. FPL expected
to generate savings of US$199 million for its customers by retiring the plants. The Cedar Bay plant was
retired at the end of 2016, and Indiantown was retired in June 2021. However, it is unclear if any provision
for just transition of workers was made
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3.3 Repurposing
Coal plant repurposing can generate an alternative cash inflow to absorb some of the decommissioning
costs that can be as high as US$100–200/kW, presenting a barrier to exit from coal generation (Huang et
al., 2021 and Raimi, 2017).
One of the key benefits of repurposing is the reuse of the site of the coal plant, which already has
transmission interconnection, and the replacement of some of the electricity or ancillary services being
removed from the power system. In addition, repurposing could potentially provide employment
opportunities for coal plant workers and allow energy systems to develop cheaper and cleaner energy
sources.
Early studies suggest that repurposing can also be cost-efficient. Repurposing benefits can potentially
outweigh decommissioning costs of older coal plants by a factor of five (World Bank,2021b). Repurposing
is attractive where coal assets generate a high level of GHG emissions and are economically inefficient,
and where it is possible to quantify the costs and cash flows associated with the repurposing exercise to
a reasonable degree of accuracy. The ability to execute capacity and grid planning at a system-wide level
is another key enabler since it can provide clarity on the repurposing option that would best serve the
needs of the grid and the energy system.
One option is for a coal plant site to be repurposed for RE generation and grid connected storage. The
new renewable generation facility can utilize existing infrastructure at the coal plant site. For example,
Otter Tail Power Company in Minnesota, USA intends to leverage existing transmission capacity at a
former coal plant to connect 50 MW of planned solar capacity to the grid. The RE plant can also stem the
loss of jobs from coal plant closures. Repurposing of coal plants into solar power generation sites created
80,000 jobs in Brandenburg, Saxony, and North Rhine-Westphalia, coal mining regions in Germany (Huang
et al., 2021).
Coal plants can also be repurposed into an RE+FLEX center. The FLEX component can be developed
through adjustments, such as converting the existing coal plant generator into a synchronous condenser
(SynCon) and building in frequency control ancillary services by attaching a flywheel to the SynCon, or by
developing a BESS at the site of the existing coal plant.
There are some practical examples of repurposed coal sites with storage, and frequency and voltage
control services. Some of the older coal generating units in the US have been converted into SynCons that
can improve grid stability, allowing long-distance power transfers and managing variability of renewables.
Other studies such as Deecke & Kawecki (2015) and Slattery & Fogarty (2015) demonstrate how
repurposing the turbogenerator of a coal plant would help in reactive power management and benefit
the power system by providing the much-needed ancillary services to manage the massive influx of VRE.
For RE utilities, reuse of coal plant land and equipment could help in reducing the cost of commissioning
a new RE asset (NREL, 2013). Chattopadhyay et al. (2019) also summarizes some repurposing examples,
including usage of the Mount Tom plant in the US and Nanticoke in Canada for solar PV; the conversion
of the 2.6 GW Drax plant in the UK to biomass; and Duke Energy’s introduction of a storage system in its
New Richmond plant site in the US to leverage available transmission capacity.
Major cost contributors include the investment costs for repurposing, decommissioning costs, and the
cost of reskilling workers. Repurposing can also provide an avenue for transition of workers and
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communities. In 2019, Endesa announced plans to replace its 1100 MW coal plant in Teruel, Spain with
1725 MW of RE and 160 MW of storage. The development of new capacity in the immediate vicinity of
the thermal power plant allowed for the creation of more than 700 jobs per annum until 2026.
As the coal plant repurposing option lowers the exit barrier, has potentially a strong economic case, can
be a versatile option that can be combined with other models, and partially addresses the social issues –
it is deemed to be an attractive option. Concessional climate financing at scale such as made available
through the Climate Investment Funds (CIF) Accelerating Coal Transition (ACT) program would be essential
for developing countries to implement such innovative RE+FLEX projects to defray some of the technology
and business risks.
3.4 Swaps or Replacement
The swap or replacement model creates the opportunity for energy buyers to exit existing contractual
obligations to purchase coal-fired energy. The buyer subsequently replaces that obligation with a contract
to purchase energy from renewable sources.
3.4.1 PPA Buyout
A variation of the replacement model is the PPA buyout mechanism, which is an asset-level mechanism
involving the provision of payments by utilities or energy buyers to coal generation companies as
compensation to exit the PPA. The structure of the compensation follows early termination provisions in
the original PPAs or, if such explicit provisions are not in the original PPAs, negotiated PPAs. Once freed
of the original PPA obligations, utilities and energy buyers can replace coal power with cheaper and
cleaner sources. This mechanism provides an opportunity to utilize private capital to finance coal
transition, particularly when applied on a smaller scale, at the asset or plant level.
It is critically important that the payment amount structured as compensation to exit the coal PPA
obligation does not overly compensate coal owners to ensure that the coal transition is executed in an
equitable and sustainable manner for all direct and indirect stakeholders. Additionally, it is important to
note that since the PPA buyout mechanism does not require closure of coal plants, there is no assurance
that the plants would cease to operate, or be decommissioned.
An example of this business model is the Kit Carson Electric Cooperative (KCEC) coal PPA buyout in New
Mexico, USA. KCEC, a member-owned utility, had a long-standing agreement to purchase coal-fired energy
from Tri-State Generation Transmission. However, KCEC identified three key issues with the contract: (i)
continuous increase in Tri-State’s wholesale pricing (by 106 percent from 2000–16); (ii) Tri-State’s cap on
self-generation, which limited members to 5 percent of total power consumed and hampered local RE
development; and (iii) lack of transparency that constrained KCEC’s ability to predict price increases by
Tri-State. KCEC pushed to revise the terms of the contract but was ultimately unsuccessful. As a result,
KCEC terminated the contract with Tri-State and entered into a new 10-year PPA with Guzman Energy,
which guaranteed fixed wholesale prices throughout the life of the contract and had no self-generation
cap.
3.4.2 Solar-for-Coal Swaps
Another variation of this business model is the Solar-for-Coal swaps model. This is typically an offer from
a third party (such as investors, energy marketers, or RE developers) underwritten by private sector
investors, to purchase and retire coal assets from a regulated utility and replace it with solar energy.
Electricity consumers would then be able to repay the coal purchase and solar investment. One of the key
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underlying drivers for the application of Solar-for-Coal swaps is consumer demand for more RE in the
power generation mix. The third party would be responsible for payment to the coal owners, retirement
and decommissioning of the plant, and replacement with new solar energy and potentially grid services.
Site remediation and financing for just transition may also be part of the package, but long-term
environmental liabilities would remain with the original coal asset owner (Energy Innovation, 2020a).
The business model depends on capital from investors to fund the purchase of coal assets, who may be
incentivized by the potential revenues from operating solar plants. Therefore, the model has the potential
to attract and mobilize private capital towards coal transition and offer cost savings for both energy
producers and consumers. The replacement solar power can be created in proximity to the retired coal
plant to leverage existing infrastructure and partially replace the employment opportunities offered by
the retired coal plant. This model would be applicable for cases where solar generation is cheaper than
coal and the savings from switching can be directed towards the cost of decommissioning.
In 2019, Guzman Energy offered to purchase all of Tri-State's coal assets in Colorado and New Mexico for
US$500 million and shut them down. As part of the proposal, Guzman offered to purchase Tri-State's
ownership in portions of Unit 2 and all of Unit 3 in the Craig (Yampa) coal plant in Colorado, the Escalante
coal plant in New Mexico, and the Colowyo coal mine in Colorado. Guzman would absorb the costs of
retiring the assets, including remediation and reclamation expenses, and subsequently solicit bids for RE
providers to replace about 800 MW of coal-fired generation capacity with 1.2 GW of wind and solar
power and sell the replacement power to Tri-State. Guzman and its investors would then be repaid
through revenue from selling the replacement RE power. Tri-State ultimately rejected the offer, stating
that its not-for-profit cooperative business model was more likely to meet consumer goals for clean power
at lower cost compared to Guzman’s for-profit business model.
This model also has the potential to be tested and scaled in developing countries. However, significant
concessional climate finance would need to be made available to enable implementation of initial
projects.
3.5 Hybrid models
In addition to standalone models, it is also possible to conceive and apply hybrid models that combine
facets of the different models that have been discussed above. For example, the asset rotation model
combines elements of repurposing and replacement. Under the asset rotation model, coal generation
capacity could potentially be replaced with RE at the portfolio level. The power generation company
would be responsible for retiring coal capacity at one site and replacing the capacity with RE at the same
site or a more suitable site. Unlike the repurposing model, this business model offers the flexibility to
situate the replacement capacity at a site that is selected on the basis of RE resource and land availability
among other considerations. However, the economic value of land and transmission interconnection at
the site of the decommissioned coal plant may not be fully realized, and support to workers and
communities would need to be carefully planned to ensure just transition.
This model has the benefit of managing the risk of stranded assets for economically uncompetitive plants,
increasing RE investment and employment opportunities, and allowing coal asset owners to participate in
RE generation.
As noted before, in 2019, Chile had 5.5 GW of installed coal generation capacity and announced a
complete exit from coal-combustion electricity generation. A coal exit commission was convened by the
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Ministry of Energy with the coal power owning companies and various stakeholders such as relevant
Ministries, electricity regulator, grid operator, municipalities, and civil society. In June 2019, a voluntary
agreement was signed between Chile’s Ministry of Energy and four of Chile’s largest utilities: AES, Colbún,
Enel, and Engie, stipulating that the utilities would decommission eight coal plants with a total capacity of
1047 MW by 2024, and the remaining 20 plants by 2040. By the end of 2020, six coal plants had already
been taken offline. IDB Invest provided US$125 million in financing for a tenor of 12 years. The package
included US$74 million senior loan from IDB Invest, US$15 million from the Clean Technology Fund (CTF),
and US$36 million from the Chinese Fund for Co-Financing LAC. The financing structure estimated the
emission reductions from coal decommissioning through a methodology tailor-made to the project. A
minimum price was imputed for the offset GHG emissions, which provided the basis for the level of
concessionality offered under CTF’s loan tranche. In the event that a regulated carbon market is created
during the life of the loan, both the CTF and Engie would share any increase in the minimum carbon price.
4 Financing Options
This section discusses potential financing approaches for coal transition. While many of the mechanisms
are illustrated through examples, some of them remain at the concept stage. Different mechanisms may
be applicable at varying scales and rely on financing from different sources. As illustrated by some of the
cases studies described above, the key to an effective strategy for coal transition lies in mixing and
matching the business models and financing options.
4.1 Reverse Auctions
Reverse auctions are an allocation and price setting mechanism that could be applied to the
decommissioning of coal plants to determine the level of compensation to be paid to the coal plant
owners. Under this mechanism, a government or public finance institution would establish a fund to
support the phaseout of coal assets, and asset owners would submit bids for the cost to phase out their
coal plants. Reverse auctions can be effective in markets with private ownership, or publicly owned plants
where the debt burden is passed along to ratepayers.
For example, Germany passed a package of “coal exit” laws on July 3, 2020 (Kohleausstiegsgesetz or KAG),
which plan for Germany’s electricity sector to phase out use of lignite and hard coal by 2038. The law will
compensate operators of coal power plants, providing lignite plant owners with fixed compensation based
on a stepwise shutdown schedule and hard coal plant owners (including industrial plants and co-
generation) with the opportunity to compete for compensation via auctions.
i
Smaller lignite-fired units
are allowed to participate in the auctions up to 150 MW.
From September 2020 – 2023, Germany’s Federal Network Agency (Bundesnetzagentur) will hold a series
of seven reverse auctions to phase out 13 GW of hard coal capacity, where plant operators will compete
to obtain compensation for shutting down their assets before 2027.
ii
Each auction establishes a price cap
per MW that the government will pay as compensation. The auction price caps decline over time to
incentivize plant operators to plan earlier closures. Bids must cover full power plants and cannot be placed
for only a fraction of their capacity.
The first auction was held on 1 September 2020 for an anticipated closure of 4 GW of coal-fired power
plants by July 8, 2021. The auction was oversubscribed with 11 successful bids. 4.78 GW was allocated.
iii
Compensation was awarded to the lowest bidders per metric ton of avoided CO2. The lowest bid was
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€6,047/MW and the highest bid was €150,000/MW, with an average payment of €66,159/MW. The total
compensation allocated was €317 million.
After the auction, German regional transmission system operators decided whether plants were classified
as “system relevant”. If so, and if confirmed by the Federal Network Agency, the power plants will be kept
in reserve for a period to be determined. If not, use of coal in power stations will be stopped by July 2021.
Starting with the second auction, the ranking of bids will be modified based on a “grid factor” that is
applied to all bids from power plants that the grid operators consider system relevant and is published
along with bids of each round of auction. The grid factor is equivalent to the past annual total capacity
reserve payments divided by the total MW of systemwide capacity reserve and multiplied by a factor
decreasing each auction year by 0.5 (starting with 4.5 in 2021 to 2 by 2026). The grid factor is a value
applied to the bids for system relevant power plants, pushing them down in the order of the bidding list,
making it very challenging for system-relevant power plants to bid successfully unless offering a very low
price.
The auction design and specification of selection criteria can impact the types of plants that are selected
under such a mechanism. For example, several of the auction winners were plant operators of relatively
new hard coal power plants. Newer plants were successful in the auction in part owing to auction rules
that prioritized bids based on CO2 generated. Modern plants are operated more frequently because of
their higher efficiencies to produce lower CO2 emissions per MWh generated. On the one hand,
decommissioning more efficient plants first means that older, less efficient plants will be used in the near
term. On the other hand, newer plants would have operated for more years and may have more potential
to be repurposed.
4.2 Refinancing
Refinancing is a plant-level mechanism to allow coal asset owners to unlock lower-cost capital to fund coal
phase-out and pass on savings to electricity consumers. It requires a regular cash flow stream and would
be applicable where payment streams are assured through a PPA or through regulatory approval to charge
ratepayers. Refinancing agreements may also require the modification of contracts and tariffs to raise
lower-cost capital (RMI, 2021).
‘Debt-for-Equity’ refinancing refers to the replacement of the equity portion of unrecovered investments
with corporate debt, whether wholly or in part (Energy Innovation, 2018a). Since equity has a higher cost
relative to debt, this is expected to generate savings and lower tariff for consumers. However, the viability
of executing such an arrangement depends on the extent to which the capital structure is already levered.
For example, equity holders may consider replacement with debt a lost earnings opportunity. For existing
debt holders, additional debt to replace the equity portion in the capital structure may result in higher
risk due to increased competition for debt repayment.
4.3 Bond issuance
Bond issuance can be used to raise funding for green projects. In the context of accelerated coal plant
closures, this fixed income instrument can be leveraged for various uses, such as to cover costs associated
with plant decommissioning, and to fund the development of RE generation plants.
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4.3.1 Securitization
Securitization allows utilities to access cheaper financing by securitizing future payment streams from
customers or government entities. This section specifically discusses ratepayer-backed securitization,
which has been explored by utilities in the USA for financing the shut-down of uneconomic coal plants.
Under ratepayer-backed securitization, a utility pledges the future revenues it will collect from its
customers through usage tariffs to raise debt. If authorized by state law, utilities can create charges on
customers’ bills to provide an assured revenue stream that would increase bond ratings (Energy
Innovation, 2020b). This is expected to result in a lower cost of capital, and the proceeds can be used to
replace more expensive capital with cheaper securitized debt. This is also expected to benefit customers
since the overall cost of servicing capital is lowered.
For example, in 2019, Colorado, Montana, and New Mexico passed legislation that authorized
securitization to refinance undepreciated and uneconomic power plants. Following New Mexico’s Energy
Transition Act, in 2020, the Public Service Company of New Mexico’s (PNM) issued US$360 million in
ratepayer-backed bonds to retire its coal-fired San Juan Generating Station. PNM estimated that using
securitization to close the plant and investing in RE replacement resources would save customers
nearly US$80 million in 2023. The company plans to channel the proceeds towards two solar and battery
storage projects, providing jobs and property taxes to partially offset the loss of the San Juan Generating
Station. The bond proceeds will also provide US$20 million towards training and severance payment for
plant employees, and an additional US$20 million for worker assistance and community economic
development.
However, the application of a ratepayer-backed securitization approach should also consider the interests
of the customers. For example, PNM has faced criticism from various groups for its coal plant retirement
plans under the Energy Transition Act. It has been argued that the ratepayer-backed securitization could
in fact prevent early closure of coal plants, and that utilities should be responsible for their decisions to
invest in coal plants instead of being allowed to recoup their investments.
4.3.2 Green bonds
Green bonds are specifically created and issued to finance projects with positive environmental attributes.
The proceeds of green bonds are expected to be earmarked for eligible green projects. Large asset owners
with steady and diverse sources of revenue can utilize green bonds to finance RE to replace coal capacity.
Green bonds can be issued by governments, utilities, or IPPs with a credit rating. The bonds are rated and
priced according to the repayment risk of the issuing entity and can be issued on the back of future
revenues from projects, taxes and fees levied by a government entity, or the balance sheet of the issuing
entity that repays the bond from other sources of revenue.
An example is the issuance of US$1 billion in green bonds in 2018 by Duke Energy Carolinas (DEC) as part
of its coal transition plans. The bonds have a weighted average coupon of 3.74 percent and maturities
ranging from 3 years to 10 years. The proceeds will be used to finance green energy projects in North
and South Carolina, as part of the company’s plans to triple the amount of RE it produces and reduce its
carbon emissions. DEC has already retired 51 coal-fired units since 2010.
4.3.3 Sustainability-linked Bonds
Sustainability-Linked Bonds (SLBs) are forward-looking performance-based instruments where the terms
and structure of the instruments, such as the coupon rate, are adjusted depending on the achievement
Page | 13
of pre-defined sustainability targets and key performance indicators (KPIs). Examples of KPIs include GHG
emission reductions, increase of RE in the generation mix, and the achievement of a pre-specified
sustainability rating from an external rating provider. KPIs are to be achieved within a specified timeframe.
Unlike green bonds, the proceeds from SLB issuance are not ring-fenced to green or sustainable purposes.
This offers issuers greater flexibility in the use of proceeds from the bond.
In October 2020, following Enel SpA’s adoption of a Sustainability-Linked Financing Framework, the Group
raised £500 million through an SLB issuance at 1%, representing a financial advantage of 15 basis points
relative to bonds without sustainability features. The interest on the bond will remain unchanged to
maturity, unless Enel fails to achieve the KPI of reaching at least 60 percent RE generation within its total
installed capacity by December 2022. The achievement of the target will be certified by an auditor's
specific assurance report. In the event that the KPI is not met, a step-up mechanism will be applied,
increasing the rate by 25 basis points.
4.3.4 Emission reduction-linked bonds
Emission reduction-bonds that are still in formative stages, can be issued through the securitization of an
emissions reduction purchase or payment agreement (ERPA). In the case of coal transition, a specified
volume of emission reductions associated with the decommissioning of coal or the development of RE
can be sold at an agreed price under a forward contract to a credible buyer. The bond would frontload
the payments under such a forward contract and make them available to the issuer for implementation
of its planned actions. Upon delivery of the emission reductions, the buyer will make a payment under
the terms of the underlying ERPA. These payments would then be used to make coupon payments to the
bond investors. Investors could also choose to receive coupons in the form of carbon credits instead of
cash.
Among the key advantages of this carbon finance-linked instrument is its ability to target specific
categories of investors to raise debt for early retirement of coal and replacement with renewables. It also
provides an avenue to identify buyers for GHG emission reductions.
An example of an emission reduction-linked bond is the International Finance Corporation’s (IFC) Forests
Bond, which was first issued in October 2016, raising US$152 million. The proceeds were channeled
towards private sector projects that created viable alternatives to deforestation under the Reducing
Emissions from Deforestation and Forest Degradation (REDD) scheme. Investors in the IFC Forests Bond
were able to choose between a cash or carbon credit coupon. Investors who elected the carbon credit
coupon could retire the credits to offset corporate GHG emissions or sell them on the carbon market. A
price support mechanism from BHP Billiton ensured that the project could sell the necessary amount of
verified carbon units until the bond’s maturity.
4.4 Concessional finance
As noted before, concessional finance can play a catalytic role in coal transition by channeling, blending
and aggregating public and private capital. It has been an important component of climate action through
financing innovative renewable and storage projects over the past 12 years. The specific form of such
finance can be anything from a grant to undertake feasibility study for coal decommissioning and
repurposing study, to a concessional loan that can be blended with other sources of financing in certain
proportion, or an equity investment in a new technology. Concessional financing is not tied to a specific
Page | 14
mechanism. It is intended to be a flexible form of financing with the ultimate goal of catalyzing
investments starting from a limited pool of development financing and public sector financing to the larger
pool of private sector financing so that projects can be replicated and scaled. Climate Investment Fund
(CIF) of $8 billion was issued 2009/10 supported by nine developed nations to accelerate the process of
renewable energy investment in the developing countries. The program has been successful in scaling
clean investments over the last decade. Kazakhstan, for instance, received initial CIF financing of $55.5
million that eventually led to $612 million of additional MDB financing resulting in over 800 MW solar and
wind capacity by 2019 (Duarte, 2021).
Concessional financing can be very useful in coal transition projects regardless of the specific business
model that is put in place. The exit barriers associated with not only decommissioning costs but also the
social support programs will benefit from such financing to develop reskilling, training and compensation
programs. It can be useful to design and pilot innovative technologies including green hydrogen on a
repurposed coal site or an old generator repurposed to synchronous condenser fitted with flywheels or
the cooling water intake reservoir used for floating solar, etc. Technical assistance may be needed to
develop awareness on new technologies, design auction mechanisms that best fit a country context,
design a RE swap contract, etc. There will also be policies and regulatory changes needed to accommodate
coal transition that may include clearances needed to develop solar PV plants on an abandoned ash pond,
pricing of reactive power produced by a synchronous condenser, processes that need to be in place that
checks system security following early coal retirement, etc.
The ACT program announced by G7 in 2021 initially set at $2 billion is structured around three pillars of
governance, people and communities and infrastructure. The first pillar covers governance aspects inter
alia stakeholder consultation, building awareness and capacity and social development plans. The second
pillar focuses on socio-economic measures to minimize the impacts of transition on people and
communities including a focus on upskilling and re-skilling. The third component currently focuses on
reclaiming and repurposing existing coal infrastructure. The first phase of ACT work targets allocating $2
billion across four countries, namely, South Africa, India, Indonesia and Philippines.
4.4 Regulatory measures
Early retirement of coal plants results in undepreciated balances on utilities’ balance sheets. In the USA,
plants that retire early would undergo depreciation review by regulators to determine the investment
amount that can continue to be maintained in the consumer rate base (Energy Innovation, 2018b). In this
case, assets that are allowed to continue earning returns would contribute to increasing consumer rates.
Regulatory permission to shorten the depreciation schedule and fully recover unrecovered investments
quickly is called accelerated depreciation which may offer coal plant owners an opportunity to recover
some of their investments to incentivize early retirement.
Accelerated depreciation has also been used in other contexts to incentivize the development of RE. By
allowing new RE plants to quickly write off assets in the first few years. RE generators may be able to post
book losses to avoid tax liability for the first few years. The potential for the application of such approaches
in conjunction with the repurposing or the replacement model for coal transition remains to be explored.
Page | 15
5 Conclusion
One of the challenges in coal transition has been the identification of a technology, and business model
in conjunction with a financing mechanism that countries can adopt. As the preceding discussions suggest,
there are several alternative business models, or combinations of models, that countries could consider
depending on their national context and the set of coal plants that they target. The limited experience
with the implementation of coal transition programs has been mixed. For example, UK has seen success
with its coal transition program, without necessarily adopting a specific business model at the national
level. Australia’s experience with the buyout model, however, was ultimately unsuccessful. Therefore,
several factors need to be considered in choosing a suitable business model. This paper tries to bring
together the experience thus far to facilitate comparison of the features, enabling factors, and relative
advantages of different approaches to help countries or coal plant owners to identify models or
mechanisms that are best suited to their context. Table 1 below presents a summary of the core business
models and their pros and cons.
Page | 16
Table 1: Comparison of Business models
Model
Key features
Pros
Cons
Policy-
based
closure
• Predominantly age-based
retirement
• Market-driven, e.g.,
competitiveness of
generation in a wholesale
market
• Additional impetus through
policies including
international climate policies
and national air pollution
legislation
• Minimum disruption to
existing contractual
arrangements
• Natural attrition of coal
capacity and market driven
entry and dispatch can lead to
lower prices
• The only proven model thus
far that has seen large-scale
coal retirement in the UK and
USA
• Slow process that may primarily
target old coal plants, unless
combined with other mechanisms
• Relies on the presence of a
sophisticated, liquid and
competitive market with relatively
low or no barriers for entry and exit
• Potential uncertainty of outcomes,
e.g., if solar/wind/storage cannot
participate in the market, since they
directly impact commercial viability
of operation but may not ensure
early decommissioning
Buy-out
model
• Targeted purchase and shut
down of coal plants
• Can rely on ‘direct action’,
including negotiation by a
Party with the capability to
ensure shut down
• Requires finances to be raised
for the purchase and
decommissioning
• Can potentially lead to rapid
retirement of coal capacity
ahead of technical or even
economic life
• No major pre-condition to be
met
• Certain or at least
controllable outcomes with
targeted coal capacity
reduction
• Potentially disruptive process with
negative implications for financial
health of incumbent generators and
buyers
• Inadequate entry for generation
and ancillary services may
jeopardize system operation
• Limited experience including failed
attempts in Australia and UK in the
past
• Challenges in determining
appropriate level of compensation
to be paid to the coal plant owner
Repurp
osing
• Re-uses the land and relevant
equipment for RE, storage,
ancillary services
• Can be applied to part of a
plant (e.g., older units) or for
early retirement of the entire
plant
• Financing needs may be
relatively modest but must be
raised for decommissioning
and new assets
• Versatile and scalable model
that can co-exist with other
models
• Ownership change is not
essential and addresses social
issues through continuation
of business and part of the
workforce
• If the old site becomes a large
source of ancillary services, it
can support solar/wind
development
• Needs a case-by-case consideration
for individual plants/units in
tandem with system level
requirement of energy and ancillary
services, e.g., not all sites may be
suitable for RE generation
• Requires a compensation model for
ancillary services for the business
case to be viable
• Limited experience to date with
repurposing
Swaps
or
replace
ment
• Replaces a coal asset and
associated PPA with RE
• Existing coal PPA can be used
to refinance the RE asset
• Different approaches
possible, but typically
includes payment for solar
power plant output as well as
payment for purchasing and
decommissioning coal
• Directs efforts toward
achieving both goals of
reducing coal generation and
increasing the share of RE
• May be least disruptive to the
coal asset owners and leave
them financially whole
• Provides a high degree of
certainty with the outcome
• The nature of asset swap may limit
viability to investor-owned utilities
• Utility consumers may potentially
be at a disadvantage to pay for the
full cost of the transition that may
not be the most efficient approach
• Largely untested proposition at this
stage
A
hybrid
model
• Combines facets of different
models to form a flexible and
adaptable mechanism to fit
multiple contexts
• Financing for retirement,
repurposing and RE/storage
may use a mix of commercial
and concessional financing
• Most versatile, adaptable and
flexible arrangement and
potentially scalable
• Can support renewables
through a market-based
mechanism as well as system
operations
• Can potentially offer a high
degree of certainty through
suitable combinations
• Significant work involved in
designing and tailoring the model to
fit each country, utility and
ownership context
• Needs to address market,
commercial and regulatory issues
noted for the other four models
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While policy-based closure can provide suitable market signals, it is reliant on action by incumbents and
could be challenging to implement in rapidly growing developing countries. This may potentially lead to a
very slow process of transition unless the government actively establishes a financing mechanism for
ensuring compliance. On the other hand, business models that rely on direct action such as buyout,
presents the risk of over-compensating coal plant owners for assets that are likely to be stranded, and
absorbing the full cost may be capital-intensive, even before the costs of establishing clean energy
capacity and just transition are considered. Repurposing offers an appealing alternative by ensuring reuse
of the coal plant site and creating a source of revenue that can partially or fully absorb some of the costs
associated with decommissioning. However, this may not be feasible (or needed) for all sites and needs
to be evaluated on a case-by-case basis. The viability of swaps or replacement depends on the underlying
market structure and the terms of the PPA. It could potentially burden electricity consumers with the cost
of compensating coal plant owners in addition to paying for RE generation. Furthermore, while the
approach can terminate a contract for payments to the coal plant, it does not guarantee decommissioning.
Hybrid models may seem appealing since they allow for choosing elements of each model that would be
applicable in a given context. However, tailoring models to market contexts can be challenging and offers
limited opportunities to draw on other experiences or lessons.
A common theme across all business models is the need for system-wide planning. Even if a country’s
government does not formally adopt policy-based closure, providing a clear market signal and a plan for
coal transition can substantially mitigate the technical risks associated with coal transition. The need for
government support for coal transition is a common theme across all business models, since this directly
impacts the perception of coal plants’ economic viability and incentivizes owners to consider options for
transition.
The determination of the level of compensation to be offered to coal plant owners can be particularly
challenging. On the one hand, compensation can incentivize coal plants to retire earlier than they
otherwise would. On the other, consumers or other stakeholders would be reluctant to bear the costs for
the investment decisions of coal plant owners. Price discovery mechanisms such as reverse auctions may
be applicable in competitive markets with multiple coal plant owners or operators and where data on a
plant’s level of operation and finances is transparently available. Its applicability in different contexts
needs to be assessed further.
Financing for coal transition can be contentious. The experience thus far suggests that public financing
from the government and concessional finance from MDBs may be essential to absorb some of the costs
of transition, particularly for developing countries. Government or MDB involvement may also be
important from the perspective of managing an orderly transition and ensuring proper dismantling and
environmental remediation at the coal plant site. Refinancing and bond issuances could offer an
opportunity to raise financing from private investors. The replacement of expensive sources of capital
with relatively lower-cost capital has been proposed by many as an attractive option for coal transition.
Concessional climate finance will play an important role in operationalizing coal power transition business
in developing countries. Sources of financing such as the climate investment fund’s ACT program would
be useful in kick-starting the coal transition in coal dependent developing countries.
Page | 18
However, risk allocation across the utilities, consumers, and private investors needs to be carefully
considered to balance the interests of different stakeholders. Questions related to the extent to which
costs of transition should be borne by existing equity holders or creditors of coal plants need to be
examined explicitly. Regulatory measures have, thus far, created an opening for utilities to plan their
transition, but may create the expectation that coal transition will be financed by the government or by
electricity consumers.
While this paper does not offer definitive answers on a suitable approach for coal transition, it presents
the available set of options based on the experience thus far, and highlights questions that require further
examination. Future work may explore the applicability of different business models presented in this
paper in greater detail, their effectiveness when considered in conjunction with various financing
approaches, and options for addressing the social cost of transition.
Page | 19
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i
Germany’s larger lignite plants only have two operators, and thus a competition scheme would not function well.
ii
After 2026, hard coal plants will not be eligible for compensation, although there is a hardship clause in the law that will
consider some aid for plants that entered operation after 2010.
iii
The auction rules allowed the first bid over the total amount tendered to be filled in its entirety, so more than 4GW
was allocated.