Research Study: Options & Challenges to Financing the Coal Transition in SPIPA Countries

Berlin, April 2022

Options and Challenges to

Financing the Coal Transition in SPIPA Countries A RESEARCH STUDY BY CLIMATE & COMPANY

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Authors Amanda Schockling Juliane Miller Floris van Dedem Max Tetteroo Louise Simon David Rusnok Pjotr Tjallema

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EXECUTIVE SUMMARY This report investigates what kind of international support can be used to bring about a quicker coal phase-out in member countries of the Strategic Partnership for the Implementation of the Paris Agreement (SPIPA). In the current geopolitical context of the war in Ukraine that is set to impact the world’s energy policies for decades to come, this report carves out the challenges, the policy options, the opportunities for a coal exit and the tools that policymakers need to make an effective energy transition happen.

The current war in Ukraine is Europe’s largest political and humanitarian crisis in decades, making a short-term increase in the use of domestic coal a possible necessity in order to avoid energy imports from Russia. The current situation may even cause an acceleration of the transition to a fossil-free electricity mix in countries highly reliant on fossil fuels, whether they come from Russia or not. This report is also published in the midst of the latest release from the IPCC WG6, in which climate scientists agree with high confidence that “climate change and atmospheric CO₂ will be pervasive unless we manage to rapidly limit fossil-fuel emissions and warming” (Parmesan et al., 2022, p. 76).

The report focuses strongly on the prospects and the potential for international assistance to end coal use, especially for SPIPA countries. The first part of the report is a stocktake of existing international financial initiatives and technical partnerships for the phasing out of coal, in varying stages of implementation. These initiatives already represent good opportunities to get involved in the coal phaseout of different SPIPA countries.

We also developed a coal transition mechanism “wallet” of financial and technical instruments to engage in a coal transition and we discuss regulatory and policy options that can contribute to reducing coal in the energy mix by e.g. making its continued use less economic and less politically attractive.

The authors worked on in-depth case studies on the state of coal in China, Indonesia and South Africa, and looked briefly at the political economy of coal in India. Despite the reflection that China may not fit as a viable case study for international assistance to end coal use, this study claims it is still extremely important for the international community to continue to put pressure on China to phase out coal use to meet global climate goals.

This report concludes that some methods of hastening the coal phase-out transition are likely to be more cost- and time-efficient than others. Further research should look into the equity of a “polluter pays” principle to guide the ethics of using financial means to hasten a just coal transition. This study recommends that policymakers assess the effectiveness of coal phase-out options along the following lines: additionality of emissions reductions, speed of retirement compared to a business-as-usual scenario, just transition aspects and scalability or replicability of the option.

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TERMS AND CONCEPTS Blended Finance

“The strategic use of public or philanthropic development capital for the mobilization of additional external private commercial finance for SDG-related investments” (Blended Finance Taskforce, 2018).

Broad Transition Support

A broad term to describe the policies, options and initiatives to help implement structural changes that enable countries or regions to switch low-carbon economies and technologies.

Cess

A levy or tax imposed to raise funds for a specific purpose, for example on coal (Sumarno & Laan, 2021).

Concessional Finance

A set of financial mechanisms that are provided at below market rates to lower the overall cost and/or risk for investors and allow high-impact investments that would typically not be possible without special financial support.

Currency Conversion

Conversion rates used in this paper take the exchange rate from the last day of the year of data. Currency conversion rates taken from Oanda.com.

1 EUR = 1.1324 USD (31 December 2021) | United States dollar 1 EUR = 16,140.1 IDR (31 December 2021) | Indonesian rupiah 1 EUR = 18.0442 ZAR (31 December 2021) | South African rand 1 EUR = 7.2139 CNY (31 December 2021) | Chinese yuan 1 EUR = 84.2083 INR (31 December 2021) | Indian rupee

Levelized Cost of

LCOE

A standard tool to compare the cost of different electricity generation technologies per unit of energy. It is a measurement of the average cost of energy/electricity that is generated by an asset over its lifetime.

The calculation results in a single, easily comparable value that represents a technological option available in a particular location. Different methods exist to calculate LCOE, but most utilize the upfront investment costs, fixed and variable O&M costs, fuel costs, weighted average cost of capital, efficiency, capacity factor or the technical lifetime of a power plant (IESR, 2019). Externalities such as social and environmental costs (and benefits) are not taken into consideration.

LCOE

Requirement for renewable energy goods or services to use a minimum level of domestically produced components to increase local production and jobs.

Electricity

Local Content Requirement

Green Bonds

A refinancing instrument issued on a capital market or to a small group of investors with the purpose of financing projects with positive environmental attributes (Bodnar et al., 2020).

Refinancing

A re-evaluation of a business’s credit and repayment status, this is used when interest rates fall or to reduce risk and/or free up cash for a business.

Securitization

“A financing mechanism that pools assets which are expected to generate future revenues and sells them as a private (i.e. not governmental) debt security. A financial institution can achieve very low interest rates on that debt when there is high confidence in future revenues” (Varadarajan et al., 2018).

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ABBREVIATIONS ADB: Asian Development Bank

LCOE: Levelized cost of electricity

BTS: Broad transition support

MDB: Multi-lateral development bank

CIF: Climate Investment Funds

MEE: Ministry of Ecology and Environment (China)

CFPP: Coal-fired power plant

MEMR: Ministry of Energy and Mineral Resources (Indonesia)

COP: Conference of Parties

MOF: Ministry of Finance (Indonesia)

COSATU: Congress of South African Trade Unions

MW: Megawatt (measure of power)

CO₂: Carbon dioxide

NDC: Nationally Determined Contribution

CRF: Carbon reduction fund

NEA: National Energy Administration (China)

DMO: Domestic market obligation

NDRC: National Development and Reform Commission (China)

EBRD: European Bank for Reconstruction and Development ESG: Environment, Social, Governance

NERSA: National Electricity Regulator of South Africa

ETM: Energy transition mechanism

PCCCC: Presidential Climate Change Coordinating Commission (South Africa)

ETS: Emissions Trading System EU: European Union FBE: Free Basic Electicity (South Africa) GDP: Gross Domestic Product

PLN: Perusahaan Listrik Negara (Indonesia) PPA: Power purchase agreement RE: Renewable energy

GHG: Greenhouse gases

REIPPPP: Renewable Energy Independent Power Producer Procurement Programme (South Africa)

GSI: Global Subsidies Initiative

RUEN: General Planning on National Energy (Indonesia)

Gt: Gigatonne (measure of carbon emissions) GW: Gigawatt (measure of power)

SASAC: State-owned Assets Supervision and Administration Commission of the State Council (China)

IDB: Inter-American Development Bank Group

SEA: Southeast Asia

IRP: Integrated Resource Plan (South Africa)

SOE: State-owned enterprise

IPP: Independent power producer

SPIPA: Strategic Partnerships for the Implementation of the Paris Agreement

JETP: Just Energy Transition Partnership JTM: Just Transition Mechanism

TSO: Transmission System Operator

KEN: Kebijakan Energi Nasional / National Energy Policy (Indonesia)

UNFCCC: United Nations Framework Convention on Climate Change

KVBG: Gesetz zur Reduzierung und zur Beendigung der Kohleverstromung

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TABLE OF CONTENTS

INTRODUCTION

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Challenges of the coal phase-out

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1 - STOCKTAKE OF INTERNATIONAL INITIATIVES TO ASSIST IN A COAL PHASE-OUT

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Technical Partnerships and Programmes

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2 - OPTIONS FOR A COAL POWER SECTOR TRANSITION

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Possible Options to Remove Coal from Energy Mix Coal Transition Mechanism Wallet Just Transition Aspects

13 14 28

3 - ECONOMICS AND POLITICAL ECONOMY OF THE POWER SECTOR IN SELECT COUNTRIES

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Indonesia

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CONCLUSIONS AND FUTURE RESEARCH

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REFERENCE LIST

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ANNEX I – COUNTRY CASE STUDIES

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China India South Africa

52 58 61

ANNEX II – COAL PLANT CLOSURE AND BALANCE SHEET ANALYSIS

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Financial Initiatives

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INTRODUCTION Our modern economies and societies have been running on coal-fueled power since the Industrial Revolution began in Britain in the late 18th century. Coal-fueled power brought the advent of large-scale heat, electricity, technology, and more, but coal combustion has also been one of the main anthropogenic drivers and causes of the climate crisis which has warmed the atmosphere (IPCC, 2021). As of 2022, coal-fired power has accounted for 30% of all global carbon emissions (Cuming & Godemer, 2021). Although coal use is a lot lower than it was predicted five years ago, we need a continued rapid decline in coal use to meet climate goals and limit global heating to 1.5°C as set forth in the Paris Agreement (IEA, 2021e). In fact, the 1.5°C target requires a “rapid phasedown of fossil fuel emissions” and the continued dependence on fossil fuels for economic development is limiting our prospects of meeting the 1.5°C target (Hansen et al., 2017, p. 578). The benchmark is clear: all OECD, Eastern European and Former Soviet Union countries need to phase out coal by 2030 followed by a global coal phase-out by 2040 to stay compatible with the Paris Agreement pathways to limit global heating to 1.5°C (Parra et al., 2019).

From an emissions reduction perspective, the two main aspects to a phase-out of coal in the power sector are to stop the construction of new coal power plants and to transition away from existing coal-fueled assets (IEA, 2021e). Littlecott et al.

(2021) claims 2021 saw the “collapse of the global coal pipeline” as proposed coal power plant projects shrunk by 75% since the signing of the Paris Agreement in 2015 (p. 6). This trend, along with the run-up to the 26th Conference of Parties (COP26) meeting at the end of 2021, which prompted many major international financing institutions and governments to make public commitments to effectively end all international financing of new unabated coal plants, shows that most, but not all, construction of new coal is declining. While the issue of coal transitions has been explored to quite some degree in developed, OECD countries like Germany, the UK and France, viable large-scale strategies to financially power down coal assets in developing countries, especially large coal producers and consumers like India, China, and Indonesia, is not happening fast enough.

The objective of this study is to address the political, economic and social constraints that need to be considered when designing international support efforts to phase out coal around the world. This study provides a stocktake of existing and planned

international financial initiatives and technical partnerships to assist in other countries’ coal phase-outs (chapter 1) and a case study of the power sector and political economy of coal in select countries (China, Indonesia, South Africa and, briefly, India; chapter 3). This exercise is meant to provide examples of the considerations that must be accounted for in climate finance efforts and the type of information that a feasibility study of a financing mechanism should address before attempting to engage in a country. A financial analysis of coal companies (Annex II) seeks to exemplify how financing directed to coal through subsidies, tax breaks, preferential finance, or guaranteed finance destablizes the playing field for renewable energy (RE) technologies to compete with coal power.

The centerpiece of this paper is the assessment of alternative options to remove coal from the energy mix through policies, standards or other non-financial means and the coal phase-out toolbox or ‘wallet’ of financing mechanisms (chapter 2). These mechanisms are an introduction into the types of financial tools that international actors could use to e.g. international financing towards supporting efforts for phasing out coal in a particular country or region. The climate financing checklist synthesizes learnings from the paper into a bite-size framework of the considerations for international engagement to be successful in helping a just coal transition.

“All OECD, Eastern European and former Soviet Union countries need to phase out coal by 2030 followed by a global coal phase-out by 2040 to stay compatible with the Paris Agreement pathways to limit global heating to 1.5°C.”

This research paper will explore the economics of climate finance options available to engage internationally with a just coal transition, with a focus on coal-fired power plants and to a lesser degree coal mines. Additionally, this paper is an acknowledgement of the global need for “new coal transition solutions to address the social and economic complexities of the [energy] transition while responding to the urgency of the climate challenge” (Calhoun et al., 2021, p. 6).

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Challenges of the coal phase-out

coal mining jobs are inside that country and that coal is seen as a geopolitically secure energy option.

Before addressing the existing financial initiatives to engage in a Just Transition, we will look at the challenges that prevent policymakers from exiting coal.

An unmanaged phase-out of coal in export-oriented countries, like Indonesia and South Africa, might bring about significant economic and social hardship if both coal plants and coal mines are shuttered. With 74% of South Africa’s energy generation coming from coal, a limited domestic industrial production, high levels of unskilled workers and a coal sector which employs about 120,000 people (Climate Transparency, 2021; Hanto et al., 2022), closing down CFPPs in South Africa has significant policy implications that need to be considered carefully – especially in cases when the country already suffers from power blackouts. Additionally, a focus on the closure of domestic coal powered electricity may result in higher coal exports to other countries and not necessarily lead to a world coal phase-out, which is why the learnings from this report can be shared across countries and national borders. Further, the boundaries of a coal transition should determine the inclusion or exclusion of the coal mining and/or coal electricity sector to fully distinguish the extent of the transition one is referring to.

Coal Lock-In Though the mining and burning of coal for energy is carbonintensive and the initial investment into coal-fired power plants (CFPPs) requires high levels of upfront capital (CAPEX), coal power provides a large and steady supply of electricity at a relatively low operating cost when operating over multiple decades (IEA, 2021c).

Due to the large upfront CAPEX, there is an inherent incentive to operate plants for a long time, which is not compatible with climate scenarios aiming to limit global heating to 1.5°C. Another factor which locks in coal use is the fact that 80% of coal consumed worldwide is produced in the same country where it is burned. The availability of domestic coal reserves means that

Figure 1. Existing and planned coalpower powercapacities capacity of of SPIPA SPIPA1 countries Coal countries (existing and planned) Some countries, like South Korea and Canada, have no plans for installing new coal capacity.

Russia

41,770 +2,193 335

5,680

South Korea

Canada

38,114 +0 4,180

United States

Japan 50,114 +500

226,978

5,470

+300

1,400

Iran data not available

Mexico

+5,378

3,177

China

Brasil

+1,666

375

1,064,401

Saudi Arabia data not available

Argentina

+158,446 92,319

India

Legend 10,000 MW Existing Coal Capacity (MW) Planned Coal Capacity (MW) In Construction Capacity (MW)

Australia

Indonesia

South Africa 43,409

231,947

40,162

24,677

+1,470

+23,893

+10,840

+1,000

2,400

31,340

15,419

Chinaʼs current and future coal capacity dwarfs most other countries, which is why it is so important to address

Source: Burak Korkmaz, 2022

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PIPA-member countries include the following: Argentina, Australia, Brazil, Canada, China, India, Indonesia, Iran, Japan, Mexico, Russia, S Saudi Arabia, South Africa, South Korea and the United States and the programme aims to facilitate exchanges on climate policy and good practices between the EU and non-European major economies.

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Existing and Future Coal Power Capacity Approximately 83% of all coal power capacity (in MW) is located in SPIPA1 countries (Figure 1). Further, 71% of all planned future coal power capacity is located in SPIPA countries (Global Energy Monitor, 2021). Therefore, a focus on SPIPA countries in this paper is extremely relevant as the impact of current and future coal use in these countries is crucial to making or breaking global climate goals.

Ensuring a Just Transition Any fundamental, structural transformation in the economy is likely to cause gains and losses for different sectors and different actors or social groups. In a well-managed coal transition, one might expect losses to be concentrated only in the short or medium term. However, it is presumed that poorly managed transitions can have much longer-lasting negative impacts on families, communities and regions. Energy transitions throughout history have been difficult, but they have been more ‘energy additions’ than true transitions from one fuel to another. The 21st-century energy transition should be a complete switch from hydrocarbons to a net-carbon-free energy system rather than an energy addition (Yergin, 2021). Thus, it is presumed that if social, economic and climate justice aspects are not considered when designing and implementing the impending energy transition, then there is a high risk of injustices and inequities (Lui & Rogner, 2021). A truly just transition must lift all members of society if we wish the energy transition to have meaningful societal and social co-benefits from a coal phase-out, like less localized pollution from coal mining and use, more economic diversification of coal mining regions, more job opportunities for old coal-regions and more. When thinking about the ways to enable international investments to aid in a quicker and just transition away from coal, as we do in this paper, it is essential to consider the potential trade-offs, distributional impacts, and transitional arrangements that may arise as coal is phased out, as well as the net effects of replacing coal e.g. with renewables.

Without an eye on the socio-political aspects of the energy transition, existing inequalities in these countries, especially those in the Global South, may be sustained and could even worsen in a transition.

Further challenges to a coal phase-out appear when examining the energy transition experiences of countries or regions in certain periods of time. For example, coal’s share of the EU’s electricity mix has fallen from a peak of 26% in 2012 to 13% in 2020 (Moore et al., 2021). In 2017, the EU coal sector employed

around 237,000 people directly, with the vast majority of them being in the mining sector, amounting to 185,000 jobs and around 52,000 at CFPPs (Alves Dias et al., 2018).

The number of indirect jobs dependent on coal mining is estimated to be around 215,000 (Alves Dias et al., 2018). Compared to the number of employed people in the EU, totaling around 186 million in 2017, this is a very small portion (Eurostat, n.d.). However, coal affects certain regions disproportionately as jobs related to coal are often concentrated. There are twenty regions in the EU that directly employ around 200,000 people in coal jobs, mostly located in Poland and Germany (Alves Dias et al., 2018). These regions are especially targeted as part of the Just Transition in the EU. The coal transition is still ongoing in the European Union (EU), especially in Eastern European countries, even though phasing out of coal was seen as ‘low hanging fruit’ in decarbonization efforts to meet net-zero by 2050 (Galgóczi, 2019). In the EU and the United States (US), coal-fired power lost competitiveness over the past decade due to regulation and the availability and decreasing costs of gas and renewables (IEA, 2021e; Kanak, 2020).

However, uneconomic coal is not yet the case in all countries around the world, sometimes due to political structures (including corruption), policy incentives or social acceptance still working in coal’s favor. The problem is that there are still too many coal power plants in operation and in planning around the world (Figure 1), which is why additional and innovative finance and continued efforts are urgently needed to replace coal from the world energy mix before 2040.

While we know that coal transitions are technically feasible and affordable, it is necessary for governments to take ownership of the transition by establishing a dedicated policy framework to support a fair and managed transition, create a transparent dialogue with affected stakeholders in preparation for the transition and engage the appropriate stakeholders early in the process (Sartor, 2018). Even if countries are not actively managing the transition themselves, major coal exporters like Russia, South Africa, Indonesia, or Australia will be forced to face the transitional effects of globally declining coal demand. Therefore, it is wise that countries start to plan for a coal-free future to prevent inequities and injustices arising from the impending energy transition.

“There are still too many coal power plants in operation and in planning around the world, which is why additional finance and continued efforts are needed to replace coal from the world energy mix before 2040.”

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1 - STOCKTAKE OF INTERNATIONAL INITIATIVES TO ASSIST IN A COAL PHASE-OUT Since around 2015, major international financial institutions have continued to make publicly disclosed commitments to effectively end their international financing of new unabated2 coal plants (Finance Is Leaving Thermal Coal, n.d.). Besides bringing the end of financing of new coal power closer to reality, it is also important to reduce the lifespan of existing and running

UN commitments by no means predict what the global coal transition will look like, it may say something about a country’s priorities, political abilities to commit to ambitious climate goals, and the help they are getting from other countries. For additional information on decisions made at COP26 see Box 1.

CFPPs. At COP26 in Glasgow, 23 nations and multiple other subnational entities, including SPIPA countries Indonesia and South Korea, made a non-binding commitment to phase out their existing coal power in the ‘Global Coal to Clean Power Transition Statement’. Unfortunately, with major coal-burning nations such as China, India, the United States (US) and Australia missing from this commitment, a significant amount of the global coal fleet is unaccounted for and unaligned with Paris Agreement climate benchmarks (Parra et al., 2019). Though

The following section aims to provide an overview of the most important existing international technical and financial efforts to end coal-fired power around the world. Financial incentives – agreements which promise funding in the form of grants and/or concessional finance in exchange for an accelerated schedule of shutting down coal plants – are differentiated from technical partnership programs, which are focused on knowledge sharing, technical assistance or transition assistance for coal regions.

Box 1: Key decisions and outcomes from COP26 in Glasgow (CSE, 2021) Finance-related decisions made at COP26:

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The Glasgow Climate Pact: signed by almost 200 countries, this agreement to “phase-down” coal signals to investors and executives that the ‘net-zero imperative’ is a commitment and it will affect businesses, supply chains and financing models.

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Article Six – Rule Book: Article 6 guides countries to generate cheaper GHG reductions. The Paris Agreement Rule Book was finally agreed upon to ensure common rules and allow stakeholders to scale up cooperation and mobilize essential private finance.

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The Glasgow Financial Alliance for Net Zero: A global alliance of financial institutions including banks, insurers and investors which signals a commitment to deliver USD 100 trillion (EUR 88 trillion) over the next three decades to meet net zero by 2050 targets.

•

International Sustainability Standards Board (ISSB): The International Financial Reporting Standards agreed upon and established a unified and consistent sustainability-related corporate disclosure to provide financial markets with high-quality data and disclosures on sustainability issues that will help inform financial decisions and investors.

Unabated coal power generation is described by the G7 and the International Energy Agency (IEA) as the use of coal power that is not mitigated with technologies to reduce CO₂ emissions, such as Carbon Capture Utilisation and Storage (CCUS).

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Financial Initiatives Just Energy Transition Partnership (South Africa) The most recent international initiative announced at COP26 aims to speed up the coal phase-out with a ground-breaking USD 8.5 billion (EUR 7.7 billion) in the Just Energy Transition Partnership (JETP) deal to support South Africa’s Just Transition to clean energy (European Commission, 2021c). The long-term plan is to provide a blended debt facility in the form of various financing mechanisms including grants, concessional loans and risk-sharing instruments to mobilize the private sector.

This partnership will aim to accelerate the decarbonization of the South African economy by targeting the coal sector and encouraging the shift from coal to RE. This initiative is predicted to prevent between 1 and 1.5Gt of CO₂ emissions over the next 20 years (European Commission, 2021c).

The forthcoming details will likely draw from the Just Transition ideas of local think tank Meridian Economics and stateowned electricity company Eskom, while the full plan will be designed and led by the national government and supported by international donors. In 2022/2023, South Africa needs to provide an explicit financing plan for meeting its more ambitious nationally determined contribution (NDC) and detailed plans and financial assessments for its Just Transition for the deal to progress (Burton, 2022).

Energy Transition Mechanism (Southeast Asia) The Energy Transition Mechanism (ETM) is an effort led by the Asian Development Bank (ADB), designed in partnership with UK insurer Prudential, to support the early retirement of coal plants in Indonesia, Vietnam, the Philippines and Pakistan (order of countries reflects the readiness of the programs, as explained in an interview with ADB). The ETM will be made up of two separate funds. The first is the so-called carbon reduction fund and the second is the clean energy fund. The purpose of the carbon reduction fund (CRF) is to provide a blended finance mechanism that brings together stakeholders in order to incentivize the early retirement of coal-fired power assets. This fund will restructure current debt-structure, thereby reducing the lifespan to achieve a certain planned Return on Investment.

The second fund, the clean energy fund, will invest in the

growth and expansion of renewable power to replace the dirtier power. For ADB’s ETM pilot-phase in Indonesia, the mechanism is planned as a blended finance vehicle funded by private or public investors working in collaboration with the Indonesian government and state-owned electric utility PLN. The idea is that the CRF funds an early retirement of current coal assets in 15 years, much earlier than the average expected lifetime of 30-40 years, while the clean energy fund invests in RE. Although the Japanese government pledged USD 25 million to support the initiative, ADB is looking to concessional loans and philanthropic funds to finance the CRF (T. Kobu, personal communication, 22 March 2022). The ADB has conducted initial feasibility studies in the three countries, but the fund structure draft is not due until June 2022 (Towards a Swift and Just End to Coal, 2021).

Although Vietnam, Indonesia, and the Philippines have very different characteristics in terms of market structure, renewables potential, and governance, they each have extremely young fossil fuel generation fleets and many assets are owned by independent power producers (IPPs) covered by long-term PPAs (M. Brown, 2021). The high and still growing concentration of CFPPs in the Southeast Asia (SEA) region combined with other barriers has made it difficult for funders seeking to accelerate the energy transition there (M. Brown, 2021). It has yet to be seen whether ADB can effectively create a public-private funding vehicle to decommission coal assets and fuel decarbonization efforts in the SEA region.

Accelerating Coal Transition (ACT) Fund Climate Investment Funds (CIF) is one of the largest active climate finance mechanisms in the world. Since its founding in 2008, CIF has contributed to climate action across 300+ programs in 72 developing countries and has been successful at raising USD 60 billion (EUR 53 billion) in co-finance (USD 19 billion (EUR 16.8 billion) from the private sector alone) (CIF, 2021).

CIF created the Accelerating Coal Transition (ACT) investment program in 2021, the first-ever effort to advance a transition from coal power to clean energy in emerging economies. G7 countries, including the US, UK, Germany, Canada, and Denmark, pledged to commit to the initiative with USD 2.5 billion (EUR 2.2 billion) which will first benefit South Africa, India, Indonesia, and the Philippines (CIF Begins Historic $2.5B Coal Transition Pilot in Four Developing Countries, 2021). It is expected that these concessional resources will mobilize up to USD 10 billion (EUR 8.8 billion) in co-financing from the private sector (Our Shared Agenda for Global Action to Build Back Better, 2021).

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The ACT will invest in the de-risking, piloting, and scaling of investments across three critical dimensions of the coal transition including governance, people/communities, and infrastructure. In practice, this means that “the ACT” provides primarily funding for energy alternatives more than financing a coal phase-out, though ADB confirmed that some concessional funds from the ACT will contribute towards their ETM’s carbon reduction fund (T. Kobu, personal communication, 22 March 2022). The ACT will provide concessional financing with technical assistance through CIF’s six multi-lateral development banks (MDBs), including the ADB and IDB.

Critical Reflection of Initiatives It is important to note that the international initiatives named thus far are still in the planning and development phases. According to our research, until early 2022, none of these investment funds have yet disbursed funding.

One critique is on the probability that developed nations deliver the full magnitude of commitments to these funds. Even though G7 countries ‘plan to commit’ to the ACT Fund, this does not guarantee deliverance, as exemplified by the predicted shortcoming of developed countries to deliver USD 100 billion (EUR 88.3 billion) to the Green Climate Fund by 2020 under the Paris Agreement (Wilkinson & Flasbarth, 2021). Though figures for 2020 will only be finalized in 2022, the calculated climate finance provided and mobilized by developed countries by 2019 was calculated at USD 79.6 billion (EUR 70.2 billion), falling short of the committed amount by 2020 (OECD, 2021). Developed countries commitments to delivering climate finance in the form of coal asset closure assistance should be perceived with a heavy amount of skepticism until such a promise is delivered.

While this paper emphasizes the importance of financial support for a coal phase-out, the provision of concessional financing, technical assistance and knowledge transfer are also crucial instruments because they allow MDBs to support local financial institutions in the coal transition.

Technical Partnerships and Programmes Powering Past Coal Alliance (PPCA) The PPCA launched in 2017 to “secure commitments from governments and the private sector to phase out existing unabated coal power” (Powering Past Coal Alliance (PPCA), 2022). Its 165 members include governments, businesses, and other organizations and they have been successful as a diplomatic public relations body in positioning a coal phase-out at the center of climate discussions, like those at the COPs. The PPCA plans to support coal-consuming countries by connecting them to the technical and financial support to maintain energy security, improve the affordability of RE and promote a Just Transition from coal power and tackle broader development challenges. The PPCA’s Finance Taskforce, launched in 2020, works with members of government and finance institutions to stop new investments in coal power, phase out existing coal power and increase investments in clean energy. The PPCA’s Just Transition Taskforce works to ensure that coal exits are socially equitable. To join the PPCA, public and private sector members must commit to take ambitious actions on coal phaseout, but there is no requirement to provide financal support for a rapid coal phase-out (Powering Past Coal Alliance (PPCA), 2022).

Coal Asset Transition Accelerator (CATA) This new accelerator launched by the European Climate Foundation and funded by several philanthropies, including the IKEA Foundation and the Growald Climate Fund, aims to speed up the fair transition to clean energy systems.

Announced at COP26, it is planned to launch during spring 2022. It will be a platform to “empower governments, utilities, companies, financiers and civil society organizations with the latest resources and best practices to implement and scale Coal Transition Mechanisms (CTMs) globally with a focus on social justice” (ECF, 2021). CATA will initially work in locations they claim are already deeply engaged with the energy transition, such as South Africa, Indonesia and the Philippines.

The platform’s initial partners are with Climate Smart Ventures in Singapore, the Carbon Trust in the UK, RMI in the US and the International Network of Energy Transition Think Tanks. There is no mention of providing funds to close coal assets in coaldependent countries or economies already in transition, but it highlights that it will provide analysis and expertise as well as a 11

Technical Assistance Fund to provide advice to those countries seeking to use CTMs to close their coal assets. CATA aims to be the knowledge center or platform for countries and financial organisations seeking to use or contribute to CTMs.

Energy Sector Management and Assistance Program (ESMAP) A similar platform that supports coal regions in transition is run by the World Bank. It currently has funding up to USD 6.9 million (EUR 6.1 million) but to date has only disbursed USD 3.0 million (EUR 2.6 million). ESMAP cooperates with the Platform in Support of Coal Regions in Transition: Western Balkans and Ukraine where funds are dedicated to financing transition projects and programs, especially in the context of funding and financing needs. It is unclear, however, whether any funds will be directed towards helping speed up the coal transition of these regions.

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SA

LE

2 - OPTIONS FOR A COAL POWER SECTOR TRANSITION

Reduced Emissions

EMITTER 1

CAP AND TRADE

PU

RC H

AS E

Emissions cap

EMITTER 2

This chapter presents the tools for policymakers and financiers to begin crafting financial mechanisms targeted at engaging internationally in a global coal phase-out. The first section discusses mainly non-financial regulatory and policy options to speed up the removal of coal from the energy mix while the second section discusses specific financing

2008; Sartor & Berghmans, 2011). During these periods the lower bound of the carbon tax fluctuated from around 15 to 25 EUR/tCO₂, suggesting this is the minimum level of taxation for it to be meaningful (Trading Economics, n.d.). Rising carbon prices under the EU-ETS has impacted coal plants by making an estimated 4 out of 5 coal plants uneconomical and unprofitable

mechanisms which could be internationally funded to encourage the phase-out of coal in specific countries or regions.

within Europe (European Commission, 2021b). These carbon prices have also allowed wind and solar power to compete without subsidies (Europe Beyond Coal & Sandbag, 2019).

Possible Options to Remove Coal from Energy Mix The following subsections briefly explore regulatory and policy options available to help speed up the energy transition away from coal. Most of these options have been used in some countries, but there is potential for international engagement in the technical set-up of these options and for knowledge sharing on how they can work.

Introduction of an Emission Trading System (ETS) Carbon pricing seeks to put a price on every tonne of CO₂ emitted and gradually reduces the amount of allowable carbon credits on the market, thus quantifying and reducing greenhouse gas (GHG) emissions. The EU first implemented an emission trading system (ETS) in 2005, but for over a decade the carbon price and the overallocation of emission rights had little, if any, effect on the operation of CFPPs. Up until 2012, emission allocations to the power sector were essentially granted for free. Moreover, during the period from 2012 to 2017, EU-ETS carbon prices were at very low levels (around 3-10 EUR/tCO₂) which did nothing to encourage coal power plants to close (Europe Beyond Coal & Sandbag, 2019). However, there is ample evidence that during periods of meaningful carbon prices (e.g. in 2005-2006, 2008-2009 and 2017-2022), switching from lignite to hard coal and from coal to gas has been incentivized (Delarue et al., 2008; McGuinness & Ellerman,

Implementing an ETS is an efficient instrument to reduce the production of coal-fired power provided so that the carbon price is not so low as to maintain the status quo. Carbon pricing can also generate significant revenues for supporting new technological investment or for supporting the Just Transition.

For instance, at prices of 60 EUR/tCO₂, the EU-ETS issues allowances each year worth around EUR 90 billion. Some of these funds are used to support national budgets, to finance a Just Transition Fund, an energy system Modernization Fund and an Innovation Fund (European Commission, n.d.-a). However, the introduction of an ETS cannot be the only policy to aid the coal phase-out.

Even though ETS systems can generate significant revenues and be directed into climate programs, the ultimate impact on reducing carbon emissions may be minimal if the caps are non-binding, the prices are too low, important sectors are not covered, or if emissions can leak regionally or horizontally into other sectors (ICAP, 2018; Schmalensee & Stavins, 2017). As of 2021, only 16% of global GHG emissions were covered by a carbon price and with average prices in March 2022 below USD 40 (EUR 35) per tonne of carbon. Achieving the goals of the Paris Agreement with this carbon price will be difficult according to the High-Level Commission on Carbon Prices (ICAP, 2021; Klenert et al., 2018).

To avoid an oversupply of carbon allocations and a deflated price of carbon emissions, lessons can be learned from the implementation of the EU-ETS. In phase 4 of the EU-ETS (20212030), the cap on GHG emissions is decreased by 2.2% per year 13

to ensure that total emissions covered under the ETS falls over time, but the proposed ‘Fit For 55’ legislative package proposes a further 4.2% reduction of ETS certificates per year (European Commission, 2021a). Some further adjustments were made

by Member States to ensure the successful functioning of the EU-ETS. For instance, the Netherlands introduced a carbon price higher than the EU-ETS to prevent the carbon price from collapsing and Portugal introduced a single-fuel levy on coal to isolate it as a dirty fuel source and promote a faster coal phaseout (Europe Beyond Coal & Sandbag, 2019). In the fall of 2021, Austria proposed a national ETS which aims to cover emissions from the transport and building sectors, which will only be covered by the EU-ETS starting in 2026 (Damberger, 2022). Their proposed eco-social tax reform will price emissions from these sectors sooner and provide a regional climate bonus to citizens to compensate for the extra cost to citizens. Initiatives like these are proof of efforts towards making the energy transition just.

Outcomes from the EU-ETS show that electricity generation from hard coal and lignite declined by 64% and 29% between 2005 and 2019 and an increase in electricity generation from RE sources was seen during the same period (Nissen et al., 2021). Under the EU-ETS, burning coal and other fossil fuels for power has become more expensive and made RE sources more attractive.

Similar lessons were learned from California’s cap-and-trade program and the Regional Greenhouse Gas Initiative (RGGI) of Northeastern states of the US. Low prices per tonne of carbon were set as policymakers were afraid to create an ETS that bites.

In California, prices began at USD 10 (EUR 8.8) per tonne in 2012 and were only planning to reach the threshold of USD 65 (EUR 57) in 2021 (California Cap and Trade, n.d.), while the RGGI was on average USD 3.76 per tonne of carbon across 2017 (ICAP, 2018).

It is worth noting the instruments used in multiple ETS instances which manage the carbon price and quantity while ensuring market stability. Carbon price ceilings, floors, and reserve mechanisms used in several ETS instances can ensure that an ETS is not overly weak while easing policymakers worries about adding too many costs (ICAP, 2018).

The introduction of an ETS may be more important in later stages in developing countries, as successfully implementing an ETS is dependent on acquiring the necessary political commitment, resisting vested interests, and setting up sufficient measuring, reporting and verification systems (Price, 2020). On top of that, it is important to avoid the mistakes made, e.g. in the EU-ETS of an oversupplied and underpriced carbon market.

The introduction of carbon markets in countries should also

address how to treat delayed coal decommissionings claiming to be carbon ‘savings’ to salvage any last value before shutting down coal assets and boosting returns for investors (M. Brown, 2021). Lastly, it is important to note that although carbon pricing can play an important role in the coal phase-out, by itself it cannot drive a Just Transition which is a crucial element especially in lower-income countries.

Targeted Tax on Coal Current rules of market economies often allow economic agents to externalize the many environmental costs and transfer them onto society and the environment. The externalities of coal, however, are often not represented in the actual price, creating a market incentive to keep production costs low. A carbon tax, a levy on units of emitted carbon dioxide, could help governments to internalize these costs in market prices to reflect the true costs of coal in economic activities (Pegels, 2018). While an ETS sets a limit on emissions and lets the market determine the price, carbon taxes set a fixed price per tonne of emissions, leaving it to the market to determine the quantity of emissions.

One of the main advantages of the carbon tax, compared to an ETS, is that it is often easier to implement (Putra & Jabanto, 2021). A carbon tax can often be implemented using an existing tax administration framework and it does not require a new and complex monitoring, reporting and verification method (United Nations Handbook on Carbon Taxation for Developing Countries Chapter 3: Designing a Carbon Tax, n.d.). It is important to note that even though an ETS is much more difficult to implement, it is estimated to mitigate pollution at a lower net cost to society (Hu et al., 2020; Putra & Jabanto, 2021).

When introducing a carbon tax, it is important to carefully develop and implement it to suit the unique political economic structures of the locality in question (as demonstrated in the case studies in Chapter 3 and Annex I). The UN Handbook on Carbon Taxation for Developing Countries differentiates two approaches to carbon taxes: fuel-based carbon taxation and direct carbon emission taxes (United Nations Handbook on Carbon Taxation for Developing Countries Chapter 3: Designing a Carbon Tax, n.d.). The ‘Fuel Approach’ is a levy on specific fossil fuels and their derivative products and is the most widely adopted and also implemented by the EU. In the ‘Direct Emissions Approach’, implemented amongst others by Chile, emissions produced by generators are measured and the tax is calculated based on these emissions. Factors such as power boundaries, scale, scope of the tax, sectors and activities to be 14

covered and whether to differentiate the taxpayer from the consumer should be considered when designing a carbon tax.

The same handbook provides a comprehensive overview of considerations regarding these and other factors.

Ideally, the introduction or elaboration of carbon pricing schemes is accompanied by a plan to redistribute revenues to enable a Just Transition. A carbon tax can raise significant revenues and can be (partially) allocated to environmental protection and social economic benefits (Parry et al., 2017; Pegels, 2018; Sumarno & Laan, 2021). A so-called ‘cess’, a levy or tax imposed to raise funds for a specific purpose, would yield double dividends, as discussed in the case study on India (Annex I). It is important, however, to remain mindful of the fact that the political economic structures of developing countries differ vastly from OECD countries. For example, while industrialized countries often reallocate revenues for positive employment impacts, employment in developing countries is often informal with insecure social security schemes. Empirical evidence on revenue reallocation indicates that redistribution can be used in developing countries to compensate energy poverty and poverty reduction in general (Pegels, 2018).

The case study on India (Annex I) demonstrates that despite domestic forces and fossil fuel dependencies, political support for a targeted carbon tax is possible in developing countries.

India takes the ‘Fuel Approach’, taxing only coal and allocating part of the revenues to the National Clean Environment Fund.

India’s Clean Energy Cess has proven to be the most successful and most promising policy in this developing country for delivering CO₂, health and fiscal benefits (Parry et al., 2017). A comparative study on the political economy of coal in India and Indonesia shows that both countries are highly dependent on coal, increasing their production and subsidizing electricity to consumers, suggesting India’s coal cess could be an example for a new coal tax in Indonesia (Sumarno & Laan, 2021).

It is important to stress, however, that a coal tax, albeit successful or not, is not a silver bullet to a coal phase-out. In India, for example, the largest stimulus for coal projects comes from the public sector and the decision to continue these projects is more political rather then economic. India has been also advised to elaborate their carbon pricing, for example, by introducing an ETS (Climate Transparency Report: Comparing G20 Climate Action and Responses to the COVID-19 Crisis, 2020). A coal tax might be easier to implement and able to generate a lot of revenue that can be reinvested, but it does not guarantee the success of a coal phase-out. It is therefore suggested to combine this method with other options discussed in this chapter.

Mandated Closure Effects on Coal Another option to hasten the removal of coal from the energy mix is government-mandated closure whereby regulators set a date by which some or all CFPPs must be decommissioned or establish a moratorium for no new coal units. A government’s decision and public announcement of its intention to phase out coal sends the strongest signals to investors to prevent the lock-in of future coal assets and infrastructure.

One example of an effective mandated closure in the Global North is the German coal phase-out. In 2018, Germany’s Commission for Growth, Structural Change and Employment proposed an end to all coal-fired power generation by 2038 and their Climate Action Law and Coal Exit Law were passed into law in 2020 (Germany’s “Coal Commission”: Guiding an Inclusive Coal Phase-Out, n.d.). The German government set aside a EUR 4.35 billion fund to compensate coal owners through auctions until forced closures of hard coal plants begin in 2027 if any are remaining (see Section on Direct Compensation). The German government also set aside EUR 40 billion to aid in the coal regions’ transition (BMWK, 2020).

The laws also placed a ban on the building of any new CFPPs after August 2020, preventing coal from further entering the energy sector. The ‘new’ German coalition government which took power in late 2021 has agreed on moving up the country’s coal exit date to 2030, but the recent energy crisis has renewed doubts that an earlier phase-out date is possible.

The German coal phase-out’s example of forced closures if any hard coal plants remain in 2027 is the only present example of state-mandated coal phase-outs. This may be due to the threat of investor-state dispute settlement (ISDS) mechanisms allowed for in the International Energy Charter Treaty (ECT), a multilateral framework agreement for energy cooperation from the 1990s unique under international law (McCully & Meister, 2021). The ECT bypasses national laws of signatory countries in the energy sector, thus allowing electricity companies to sue the state for lost profits due to state-mandated actions, such as a mandated coal phaseout (McCully & Meister, 2021). The fear of being sued could explain why some governments are hesitant to impose coal exit policies on private companies. However, at least in the EU, this fear may soon be eliminated if the Court of Justice of the EU issues a legally binding ruling in 2022 of the same opinion it shared in August 2021 that ECT cases would not be compatible with EU law.

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While the focus in the Global North is to close the existing fleet of coal plants, since these OECD countries need to phase-out coal by 2030, the short-term focus is rather different for the Global South. Due to the large pipeline of projects in non-OECD countries (Figure 1), the Global South should focus on preventing the opening of new coal units, at least in the short-term. Therefore, a mandated closure for the Global South would look more like a moratorium on building new coal plants instead of forced closures as it becomes increasingly uneconomic worldwide to operate coal power compared to RE technologies.

Coal Plant Conversion or Repurposing Along with a coal phase-out comes the risk that new fossil gas or biomass plants are built, or coal plants are converted to fossil gas or biomass to make up for the lost capacity. For example, contracts for difference (CfD) supported the conversion of units at a CFPP to burn biomass in the UK (Littlecott et al., 2018). However, the climate costs of fossil gas or biomass does not outweigh the benefits due to the leaking of methane in fossil gas extraction and the cutting down of trees for biomass causing deforestation. There is a risk that subsidies towards CFPPs are shifted to support the co-firing of biomass and coal or the conversion of plants to burn fossil gas which would risk carbon lock-in (Europe Beyond Coal & Sandbag, 2019).

A more viable alternative to decommissioning CFPPs and reducing carbon emissions is to repurpose locations around old coal units for a variety of end uses, including solar plants, wind plants, data centers, energy storage, or even cultural or aesthetic spaces like museums. Examples of repurposing old coal plant sites can be found in Canada, Germany, the UK and the US, and could be used elsewhere in the world to prevent losing the full value of a coal plant site and infrastructure. Repurposing could capture some value from the infrastructure, such as transmission or grid connections, but it seems unlikely that the potential for repurposing a plant leads it into early retirement.

Carbon Capture and Storage (CCS) CCS technology involves the geological storage of CO₂ emissions underground as a permanent storage solution. However, even with CCS technology, around 10% of emissions are still emitted from a plant and cannot be captured, so this option is uncompatible with any net-zero emission pathway. CCS on coal plants would retrofit existing power plants to capture and reduce their emissions while they still operate, but the transportation and storage of carbon in this way is very unlikely to be feasible at a scale past the pilot-scale. CCS on coal plants is projected to reduce the efficiency of the power generation on the order of 20-30% and no full

commercial installations in CFPPs are operating yet (“Clean Coal” Technologies, Carbon Capture & Sequestration, 2021). The storage solutions include geological storage injections for enhanced oil recovery, depleted oil and gas fields, coal seam storage and deep saline aquifers storage, which would further increase the cost of operating a coal+CCS setup. Retrofitting existing coal plants to use CCS technology is not even an option for all existing coal plants as not all plants have the required space to build the needed chemical unit to capture the emissions. Additionally, all other pollutants not captured by the CCS technology will still pose a problem as well as the lower efficiency of plants with CCS technology would cause more coal to be burned.

CA P

TU

RE

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OR

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Regulation and Emission Standards Emission standards for new or existing power generation can reduce CO₂ emissions by effectively limiting the production of coal power unless it complies with certain emission requirements (IEA, 2021). Air pollution regulations can have a significant impact on the investments, costs and operations of new or existing CFPPs, making many of them more costly and less desirable (IEA, 2021).

Stringent air quality standards among other factors have resulted in the massive retirement of CFPPs in both the EU and the US. An example of failed implementation of emission standards can be seen in India and South Africa where air pollution standards couldn’t be enforced due to utilities refusing to install or use the emission technologies because it would have reduced their profits (IEA, 2021). The problem here lies in the implementation and enforcement of emission standards, not in the technologies or controls themselves.

Another tool to limit the use of coal is the use of capacity mechanisms to reward CFPPs for the MW of capacity available to produce power if needed by the grid rather than the actual MWh that they generate (IEA, 2021). This tool can ensure the security of energy availability if demand is high but pushes out coal of baseload generation.

Improving emission standards might be a relatively easy and short-term solution to implement in India or Indonesia where plants are not ultrasupercritical and therefore retrofitting these may make more sense in the short-run rather than just abandoning them.

16

Critical Reflection on Options While not explicitly mentioned as an option to remove coal-fired power generation, the promotion of RE/electricity generation projects is currently still the primary mechanism, as it is for the foreseeable future. While RE has certainly stepped in to fill the gap left by coal in both the UK and the German coal phase-out, the German example demonstrates that incentivizing and expanding RE alone is not enough to diminish the importance of coal (Brauers et al., 2020). The speed of the coal transition can depend partially on the speed, costs, potential and scale for advancing RE in a country.

Governments can define ambitious RE targets and support these targets through effective policy environments and incentives, such as feed-in tariffs, auctions and RE portfolio standards, as well as streamline permitting procedures for RE to facilitate the transition away from coal power (Climate Transparency, 2019).

(Muller & Robins, 2021, p. 3). This section will cover the financial mechanisms available for accelerating the international coal phase-out. Figure 2 shows an overview of the ‘financing wallet’.

Implemented Mechanisms The tools in this section are financial mechanisms to phase out coal that have been implemented in real life. Therefore, each subsection will also mention the preliminary successes or shortcomings of the tools’ implementation thus far. This section aims to demonstrate the financial mechanisms that have been used in a certain situation or context and what can be learned from their exemplification in the real world.

Broad Transition Support The options presented here focus mostly on limiting coal usage in the electricity mix on the demand side, but options to address the supply side of coal could include a moratorium on mines, reverse auctions to close remaining coal assets, permits, taxing of coal extraction or increasing the fee for water usage at a mine. Policy instruments overwhelmingly focus on tools to reduce demand for GHG but policies that aim to restrict the supply which produces GHG emissions is a less-explored climate policy choice that should be investigated in the coal sector (Green & Denniss, 2018).

It is also important that any climate finance engagements provide stipulations and considerations for the ‘waterbed effect’, which can occur when a decline of coal generation in one country, or many, leads to an increase elsewhere, due to lower coal prices or an increase in opportunities to export coal-fired electricity to those countries (Jewell et al., 2019). This negative effect is also called carbon leakage.

When evaluating the effectiveness of these options to remove coal electricity, it is important to consider at least the following aspects: additionality of emissions reductions and avoiding double counting emisisons, speed of retirement compared to a businessas-usual scenario, Just Transition aspects and a polluter pays principle, as well as the scalability and replicability of the option.

Coal Transition Mechanism Wallet Based on the slow pace of the international coal phase-out, it is clear that coal needs an extra incentive to shut down more quickly. Some are also calling for more innovative financial mechanisms to help “deliver the just transition, to fuel increased investments in people and communities, as well as financing a rapid expansion of renewable energy infrastructure”

Broad Transition Support (BTS) is a financial mechanism that targets more than just the closure of coal mines or power plants. The main goal of BTS is to support structural changes in an economy that is (heavily) dependent on fossil-fuels and that engages in a transition or diversification to a low-carbon economy. As such, typical BTS activities include broad activities such as investments in low-carbon infrastructure, diversification and governance of transition. It is possible, yet not obligatory, for BTS applications to earmark part of the cash flow to retire or repurpose fossil-fuel assets (Calhoun et al., 2021).

One high-profile broad transition support mechanism aimed at the coal phase-out is the EU’s Just Transition Mechanism (JTM), which is a fund aimed at helping European coal regions through a just transition. It has been adopted within the longterm budget of the EU (2021-2027) and is expected to mobilize around EUR 55 billion (European Commission, n.d.-b). The fund is built up of three pillars with different target regions and financing mechanisms. These range from grant-based funding for the most coal-dependent regions, to mobilizing private sector investments and European Investment Bank loans for regions that are economically linked to coal-dependent regions (European Commission, n.d.-b). This financing is mostly aimed at RE investments, energy efficiency, infrastructure investments and diversification. One of the main shortcomings of the JTM is that it does not have an explicit mechanism to support or accelerate the phasing-out of coal mines and power plants.

The European Commission tried to remedy this shortcoming by requiring coal phase-out plans for the Recovery and Resilience Facility following the COVID-19 pandemic.

Pay for Closure Under pay for closure mechanisms, coal plant operators receive financial compensation to close their plants. In the following 17

Coal Transition Mechanism “Wallet” To visualize the financing options available for international interests to engage in the global coal transition, the imagery of a wallet will be used. A wallet is a well-known term for a carrying-case holding oneʼs financial means or financial resources.

In this sense, this coal transition mechanism wallet holds the financial means or mechanisms at our disposal to help accelerate the global transition away from coal by paying for the removal of coal. Each ʻcardʼ has a certain color which designates its type of finance, the location differentiates tested and tried tools from theoretical tools that have yet to be tested as well as details on how it is to be used and if it has been used before, the monetary value of the carbon it paid to abate future coal emissions.

Concessional Debt

Pay for closure

Debt refinancing

Buy + retire

Blended debt facility

Debt-for-climate Swaps

Managed Transition Vehicle

Blended finance uses public and/or philanthropic capital to facilitate sector development and market building to increase the regular flow of private investment to developing economies. The public support should be temporary and aimed at increasing private fund.

A foreign creditor offers partial or complete debt relief to a debtor government in exchange for climate mitigation and/or adaptation actions, in the case of coal debt relief would be tied to the early closure of coal capacity.

Financial institutions opt for a carbon reduction facility to close coal plants + a clean energy facility to open new renewable capacity.

Compensation

Retirement-linked green bonds

Coal Retirement Portfolio

Paying coal owners or operators to shut down coal plants early.

A utility issues a bond to refinance the remaining asset balance on an uneconomic coal plant, plus any funds needed for transition assistance or decommissioning of the physical asset.

This standard bond is linked to retiring coal capacity and historic or future coal-based emissions, enabling a utility to build new renewable energy capacity through the proceeds of the bond.

Private investors purchase CFPPs from existing owners and close coal early. Investors paid back from operating revenues.

Retirement-linked green tariff

Carbon Bonuses

A mechanism used by a utility that creates a special rate class or energy delivery option for large corporate buyers to ensure its energy is directly financing a retiring coal asset and the renewable energy capacity that will replace it.

Cash payments from governments or private financiers pays a fixed amount of money per tonne of avoided carbon to reduce the cost of the early coal phase out or reduce the emissions of the asset while it is still running.

Public or private funders deploy finance with lower-than-market-rate interest and more lenient conditions to crowd-in commercial finance.

Example: IDB Decarbonization Instrument gives a EUR 97 million loan at market rates to Engie Energía (Chile) to build & operate a windfarm in Calama supplemented by a EUR 13 million concessional loan tied to actual emissions averted.

VA LU E o f C A R BON

E UR 0.73 / t CO 2

Example: A reverse auction system was implemented by the Federal Network Agency of Germany to engage owners of hard coal plants and small lignite coal plants (≤150MW) in a competitive bidding process, with the lowest bidders winning a "closure premium" to close their plants early.

Example: The proposed blended debt facility for South Africa would refinance Eskom, the state-owned electric utility, to support coal plant decommissioning and restore access to capital debt markets.

Example (in development): Energy Transition Mechanism with Indonesia, Vietnam, and the Philippines (Asian Development Bank).

VA LU E o f C A R BON

4.17 E U R/t CO 2

Ratepayer-backed Bond Securitization Investor-owned utilities issue securitization bonds that refinance debt with lower-cost capital and pay back its investors with a surcharge on customer bills. This closes coal plants early and finances a just transition and renewables fund with the extra income.

Example: Securitization is used by utilities in select US states (Michigan, Wisconsin) with more states following suit to pass securitization legislation.

IMPLEMENTED TOOLS

THEORETICAL TOOLS

section we will be highlighting an example of using concessional finance in Chile, as well as introducing the closure premiums and direct compensation used in the German coal phase-out.

Concessional Finance Concessional finance uses investments deployed with lower interest rates than found on the market, by using grants to subsidize interest. Concessional finance can theoretically accelerate the “tipping point” when building or operating a new clean power plant is cheaper than a fossil-fuel plant or when a new clean power plant is cheaper on the levelized cost of electricity (LCOE) terms than an existing fossil-fuel plant (BloombergNEF, 2019).

Chile has made a commitment to phase-out coal at the latest in 2040 but is aiming for a 2030 phase-out and joined the PPCA at COP26. As part of this commitment, the Inter-American Development Bank (IDB) launched a novel concessional finance instrument in 2020 to support Engie Energía Chile (EECL) in its decarbonization process (IDB Invest, 2021). IDB Invest provided a loan of USD 110 million (EUR 97.1 million) at market rates over 12 years for the construction and operation of a windfarm in Calama, supplemented with USD 15 million (EUR 13.2 million) at a concessional rate from the Chilean Clean Technology Fund (CTF).

The interest of the loan, provided at a floating rate, will be decreased to below market rates in relation to the number of emissions avoided by shutting down two coal power plants owned by EECL. The windfarm, with a capacity of 151 MW, started operating commercially in October 2021 (Engie Energía Chile, 2022). However, the disconnection of units U14 and U15 (125 MW capacity each) of the Tocopilla coal power plant was postponed from December 2021 to a date after June 2022. This happened on request of the National Energy Commission of Chile due to system security concerns becaue of drought impacts on hydropower generation.

In the case of Engie Energía, plants U14 and U15 were already scheduled to close in the medium term and the closure was merely brought forward by 18 months. As part of multinational energy company Engie, headquartered in France, EECL already has its own decarbonization plan to be carbon neutral in Chile by 2025 and globally by 2027.

When asked if IDB’s Decarbonization Instrument changed Engie’s decision to phase out coal or speed up the process, the company acknowledged that IDB’s financial incentive was among other arguments that ultimatively resulted in the company’s decision to phase-out coal (B. Infante, personal communication, February 8, 2022). It has however helped communicate their coal phase-out plans throughout the whole company, which is seen as a positive effect of the instrument.

Using the value of the concessional loan and the carbon reduction assumptions, the value of carbon in this tool equates to USD 0.90 (EUR 0.73)/tCO₂ (based on an early closure of 18 months), though the value IDB is paying for the reduction in carbon emissions associated with the early closure will increase slightly because the closure has been delayed (Annex II).

Closure-Premium through Reverse Auctions Germany is the world’s biggest consumer of lignite coal (Braunkohle) (Morris, 2021), which accounted for 20% of German electricity production in 2021. Hard coal (Steinkohle) meanwhile contributed 9.5% of electricity produced in 2021 (Deutscher Strommix: Stromerzeugung Deutschland Bis 2021, n.d.).

Part of the coal phase-out underway in Germany’s power sector is based on the recommendations of the “Coal Commission” and is regulated in part by the Gesetz zur Reduzierung und zur Beendigung der Kohleverstromung (KVBG) which includes compensation of plant operators through two different mechanisms.

For all hard coal plants, as well as lignite plants with a capacity of up to 150 MW, a process of reverse auction is being employed. The Bundesnetzagentur (Federal Network Agency) determines the amount of MW to be reduced in each auction round (§6 KVBG) based on the reduction targets set out in §4 KVBG. CFPP operators then make a bid for the price per MW at which they would be willing to close their plants. Since it is a reverse auction, the winning bids will be the lowest bids. Results of the auctions from 2020 to 2021 are shown in Table 1.

There are several incentives in place for plant operators to take part in the auctions (early). The maximum price that can be achieved in the auctions is set to decrease year by year, from EUR 165,000 per MW in 2020 to EUR 89,000 per MW in 2026 (§19 KVBG).

Additionally, starting from 2027, remaining plants will be subject to uncompensated government-mandated closures (§5 KVBG).

Table 1. Results of first five rounds of auctions to close coal power capacity in Germany.

Auction Round

Desired capacity retired (in MW) (actual)

Lowest - highest successful bid (EUR/MW)

1: 1st September 2020

4,000,000 (4,787,676)

6,047 – 150,000

2: 4th January 2021

1,500,000 (1,514,000)

0 – 59,000

3: 30th April 2021

2,480,826 (2,132,682)

0 – 155,000 (max. price)

4: 1st October 2021

433,016 (532,514)

75,000 – 116,000

5: 1st March 2022 (upcoming)

1,222,886

-

Total retired capacity:

8,966,872

19

While the auctions are meant to ensure that the payments are kept as low as possible, they have been criticized as ineffective and wasteful: in the first auction round, closure premiums totaled EUR 317 million and were awarded to seven plants that collectively lost over EUR 200 million in the prior two years (S. Brown, 2020). No data on the total closure premiums was published in subsequent years.

Additionally, there are concerns that RWE and LEAG will be able to cross-subsidize unprofitable coal with the financing received under the compensation (Staude, 2020). Therefore, the direct compensation of lignite coal owners in Germany is currently being reviewed by the EU Commission for possible breach of state aid law (Flauger, 2021).

Cost Direct Compensation Competitive auctions were not an option for the lignite sector, which is dominated by only two companies: RWE and LEAG. The sector is vertically integrated with RWE and LEAG owning both the mines extracting lignite as well as the power plants burning it, meaning that phasing out lignite coal becomes more complex as the reduction in mining & renaturation of mines need to be co-ordinated (Flauger, 2021). A direct compensation of EUR 4.35 billion was agreed on, with RWE set to receive EUR 2.6 billion and LEAG receiving EUR 1.75 billion (Schrems & Fiedler, 2021).

An important reason this path was chosen is to prevent legal disputes. As a result of the German nuclear phase-out that began in 2011, energy companies RWE and Vattenfall sued the state for compensation of their lost profits (Balser & MüllerArnold, 2020). The contracts for the compensation of lignite companies were supposed to prevent such lengthy legal conflicts, however, they are still controversial for a variety of reasons.

In a legal assessment, the scientific services of the German parliament found that a compensation would only be legally necessary under exceptional circumstances and should therefore only be granted in select cases (Wissenschaftliche Dienste, 2018).

Furthermore, after the compensation had been agreed on, an internal document of LEAG revealed that they expected anyway only to run their coal plants until 2040. The exit agreement for 2038 therefore only reduced the amount of coal that would be burned by 13 million tonnes, 1.5% of the coal LEAG wanted to burn until 2040 (Staude, 2020).

The process was also criticized for lacking transparency without public consultation. When the formula used to calculate the compensation was finally revealed after legal action by Greenpeace, assumptions in favour of the coal companies were revealed. For example, the assumed CO₂ price of EUR 17/tCO₂ means coal would still be competitive (Staude, 2021). However, it is far below today’s prices on the EU-ETS, at more than EUR 70/tCO₂.

In their coalition agreement, Social Democrats, Liberals and the Greens agreed to complete the German coal phase out “ideally” by 2030 (SPD et al., 2021, p. 5). It remains to be seen if this goal will be achieved amidst the ongoing upheavals on the energy market because of the Russian invasion of Ukraine.

Under the scenario of a coal exit by 2035, closure premiums and direct compensation together have a pricetag of EUR 4.2 per tonne of carbon (tCO₂) avoided. However, if payments for structural development of coal-dependent regions are included in the calculation (up to EUR 40 billion), the cost per tonne of CO₂ reduction rises to between EUR 25.4-42.8 (calculations based on (Nacke, 2020); Annex II).

Ethical Issues with Pay for Closure As the controversies around the mechanisms outlined above show, there are ethical issues associated with pay for closure initiatives. Fundamentally, they go against a “polluter pays” principle, instead paying the polluters and shifting costs to the society to bear. A study ran by Deign (2021) also showed, that some of the assets that participated in the auction had already been amortized, so participating at the auction created windfall-gains.

In Finland, a coal phase-out will have to happen before May 1, 2029, which marks the start of the ban on the use of coal for energy production (Hill, 2019). Compensation for coal plants was deemed unnecessary by the Finnish Constitutional Law Committee because coal asset owners should be reasonably aware that legislation related to their business was likely to change and that acting responsibly towards the environment is more important than commercial issues faced by coal power plants owners (Bixel, 2020; Europe Beyond Coal & Sandbag, 2019).

However, it should be kept in mind that in some situations “stranded assets could have mitigating circumstances, e.g. for implementing a timely transition for affected workers and regions, or for energy security” (Sartor, 2018, p. 25). In other words, compensation may be acceptable and even needed in some cases to ensure a quick transition for workers and avoid further stranded assets.

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Debt Restructuring Debt restructuring means that the current debt of a coal plant will be replaced with low-cost/concessional debt in exchange for funding a variety of transition activities, such as decommissioning the coal plant, investing in clean energy or supporting the just transition for workers (Calhoun et al., 2021).

The ADB developed its ETM as a debt restructuring instrument (the initial idea was to purchase the assets).

Debt refinancing is a possible refinancing mechanism which could also be applied in Indonesia and South Africa. However, as debt-equity share for South African company Eskom (20% equity, 80% debt) is much higher than for instance Indonesia’s PT Perusahaan Listrik Negara (Persero, 60% equity, 40% debt), this type of instrument might be more powerful in South Africa, than in Indonesia.

Ratepayer-backed Bond Securitization Multiple states in the US, including Colorado, Montana and New Mexico, have passed securitization legislation authorizing the use of “ratepayer-backed or ‘securitized’ bonds” to refinance utility investments in early-retired electric generation plants (Lehr & O’Boyle, 2020). In addition, energy companies in Michigan and Wisconsin have already issued or have been authorized to issue securitization bonds in order to support the early retirement and replacement of coal plants. This mechanism puts a premium on energy tariffs, to generate extra cash-flow to finance the early retirement of coal plants. A main criticism of securitization legislation is that it allows coal plant owners to recover the full remaining value of an already-dying industry and asset, which is likened to a “consumer-backed ‘bail-out’ for a profit-making utility” (Davidson, 2019).

As of March 2022, WEC Energy Group has securitized USD 105.2 million on its balance sheet which allows the utility to collect a full return of the net book value of the retired coal power plant it shut down in 2018. However, WEC Energy Group’s ability to use ratepayer-backed securitization to recover the book value of a plant that had become too costly to operate and uncompetitive with cheaper energy alternatives, such as natural gas and solar, is highly questionable. WEC Energy Group is investing hundreds of millions of USD in solar generation projects and acquisition of wind energy generation facilities to make up for the closed coal power capacity (WEC Energy Group, 2021), but one could argue that they would have anyway invested in these cheaper RE technologies even without securitization in order to recover value from closed coal plants.

In New Mexico, the Energy Transition Act (ETA), signed into law in 2019, requires 50% of electricity to be provided from renewables by 2030 and 100% by 2045 for major investorowned utilities, and by 2050 for smaller cooperative utilities (Davidson, 2019). To meet these goals, utilities in New Mexico can refinance their debt with securitization, and effectively share the responsibility of coal closure with their customers.

Securitization is beneficial for customers because it lowers the expected rate of return of the utility (from the usual 7% to 4%), adds a tariff surcharge, and also decreases the expected earnings of the utility.

Consumers are expected to benefit from the cheaper cost of electricity from renewable sources which will replace the coal power. The low-interest bonds of the ETA will directly finance a just transition through worker retraining, economic development, and decommissioning and reclamation costs.

Our conclusion is that the combination of RE replacement of coal with phase-out dates, a refinancing mechanism to lower the cost of the transition and significant funds to ensure a just transition for workers makes the mechanism more likely to succeed than if it was implemented alone.

Some caveats make securitization an option only in certain situations. For example, it cannot work well in countries without well-developed public debt markets since securitization requires new bond issuance by the utility. Development financing institutions and international support can help, but this hasn’t been tried yet. So far, the mechanism works well for investor-owned utilities which serve 72% of utility customers in the US (U.S. Energy Information Administration, 2019), so it may not work well for publicly-owned or state-owned utilities, like those in Indonesia and South Africa. As mentioned before, the success of this financing tool also depends on part of the savings being reinvested into supporting the workers and communities of closed coal plants as well as into clean energy.

Ratepayer and asset portfolio securitizations can be a form of green bonds if the bond is backed by revenue streams from a closing-a-coal plant project. Governments, state-owned enterprises (SOEs), companies or other entities with a credit rating and commitment to RE can issue green bonds to finance the closure of a coal plant and the potential replacement with RE installations (Bodnar et al., 2020). Governments and large asset owners can use green bonds to refinance the debt on their existing coal assets and replace the power generation capacity with RE sources.

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Financing Mechanisms in an early development phase The tools in this section are financial mechanisms to phase out coal that are at various stages of planning and have not yet been tested in the real world. Therefore, no results or data can be presented on the tools’ actual implementations, only predictions and expectations on their effectiveness. This section aims to cover the vast array of financial mechanisms available to phase out coal and the predicted outcomes of each.

Debt Refinancing Though the following debt refinancing tools have not yet been fully tested or implemented, the mechanisms’ goal of freeing up capital to help fund the coal transition while lowering customer costs is the same.

climate mitigation and/or adaptation actions based on agreed-upon terms, with a commitment of the equivalent or lower amount of debt forgiven (Elston, 2021; Picolotti et al., 2020). This can be done directly between the debtor and the creditor, either converting the debt to the local currency of the debtor government, lowering the interest rate of the debt or forgiving some or all the debt (Bove, 2021; Elston, 2021; Singh & Widge, 2021). These swaps can also happen indirectly through a third channel, usually an NGO such as WWF or the Nature Conservancy, which buys the debt of a country at a reduced price from a foreign creditor and cancels the debt for the indebted nation in exchange for certain funds being disbursed for climate projects (Bove, 2021; Gillespie, 2020; WWF, n.d.). Early debt-for-nature swaps work on a project basis and as such, are considered small-scale swaps, while debt-forclimate swaps have been discussed as a solution to address the overall indebtness of a country and would work on a climateprogramme base (Singh & Widge, 2021; Steele & Patel, 2020).

Blended Debt Facility Blended finance is the strategic use of development finance (e.g. grants) for the mobilisation of additional (private) finance towards specific topics, be it sustainable development in developing countries or in our case, the coal-exit. One example of a blended debt facility is the proposed JETP for South Africa whose details have yet to be worked out. Tonkonogy et al. (2018) identified South Africa among other countries in Sub-Saharan Africa as high-impact opportunities for blended finance to invest in clean energy. They cite experiences in providing blended finance for clean energy which have led to successes in unlocking finance for clean energy projects in developing economies, but it has yet to be seen if these will have similar success in unlocking finance for decommissioning coal assets in coal-dependent developing economies.

Some of the benefits of the swaps include a (partial) financial relief for highly indebted countries, the creation of jobs in green sectors or for climate action, investments by the public and private sector in sustainable technologies and infrastructures and an overall economic and green recovery (Picolotti et al., 2020). A creditor will agree to provide (partial) debt relief if they expect not to recover the full value of the debt and/or if these debt-for-climate swaps can help them fulfil new priorities, e.g. their promises under the Paris Agreement and the UNFCCC to provide funds to developing countries for their green and just transitions (Bove, 2021; Fuller et al., 2018; Picolotti et al., 2020). Steele & Patel (2020) suggest expanding this instrument to private financiers by offering carbon credits in exchange for climate swaps.

Debt-for-Climate Swaps

Several studies have analysed potential candidates for these type of debt-for-climate swaps. Certain indicators can identify and select ideal country candidates, such as economic indicators pointing out if there is a high need for debt relief; indicators related to the governance framework of the debtor country, highlighting if swaps could be dealt with effectively; and indicators related to the interest and willingness of countries to invest in climate actions (Lütkehermöller et al., 2021; Singh & Widge, 2021). Singh & Widge (2021) analysed eligible countries for an ‘Accelerated Coal Power Retirement Mechanism’ (ACPRM), which would be a mechanism funded by the avoided debt services of the debtor country with the purpose of buying and retiring coal power plants earlier than their retirement age.

From this analysis, only Vietnam and the Phillipines fulfilled the selection and eligibility criteria for the ACPRM.

Debt-for-climate swaps are instruments inspired by debt-fornature swaps, which were first introduced in 1987 to forgive a part of Bolivia’s debt in exchange for the conservation of land neighboring the Amazon Basin (Deacon & Murphy, 1997). With the COVID-19 crisis deepening the debt level of many countries, the concept of debt forgiveness in exchange for climate action has been more recently discussed (Elston, 2021; Picolotti et al., 2020; Singh & Widge, 2021). There are, to date, no debt swaps projects related directly to the phasing out of coal for energy production, however the basic structure might apply in the context.

Debt-for-climate swaps work as follows: a foreign creditor offers debt relief to a debtor government in exchange for

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So, debt-for-climate swaps could become an interesting tool to reduce the financial burden of certain highly indebted countries while helping them address their high reliance on coal power plants by establishing concrete plans to fund coal retirement through debt relief. While South African Deputy Finance Minister David Masondo and the South African Communist Party had made some comments before COP26 that they would possibly start thinking in more depth about debt-for-climate swaps, the announcements made during the COP stayed fairly vague, and it was unclear whether any debt swap will be implemented (Sguazzin & Cele, 2021). China is the largest bilateral debt holder for developing countries, so it could have an important role to play in forgiving debt in exchange for climate actions (Singh & Widge, 2021; Steele & Patel, 2020).

However, successfully implementing debt-for-climate swaps represents certain challenges: First, many countries that need partial or complete debt relief might not be able to commit to much climate action, for instance the shut down of coal plants (Widge, 2021). Although these swaps would take place in situations where a country is at risk of defaulting, investing the relieved debt into climate actions might be difficult for countries which already face financial difficulties (Steele & Patel, 2020; Woolfenden, 2021) Previous experiences with debt-for-nature and debt-for-climate swaps have shown that these swaps have slightly helped reduced the debt stock but have lacked a substantial contribution to debt sutainability (Fuller et al., 2018; Steele & Patel, 2020). This would mean that a successful and significant mobilization of capital would most probably come from countries still able to service their debt, but which need an incentive, such as debt reduction, to invest into climate actions.

Second, arranging debt swaps is complex as both governments participating in the financing must find a common agreement, which could undermine their effectiveness in tackling urgent issues related to the climate and debt crisis that many countries are facing (Caliari, 2020; Woolfenden, 2021). It becomes especially complex if the donor government insists on a co-financing (fresh cash flow).

Third, two difficulties arise regarding the contribution by creditor countries to the Paris Agreement and the UNFCCC promises.

First, the finances provided by the creditor country as debt relief need to come in addition to other support from that creditor towards climate adaptation and mitigation measures, and not as a substitute (Steele & Patel, 2020). Second, the total climate impact of the investments funded by the debt swaps must only be counted once, either by the creditor or the debtor country, otherwise one faces a major double-counting issue.

It is therefore currently uncertain whether debt-for-climate swaps can be an adequate and successful tool to help countries both with their level of indebtness and to transition out of coal. A similar example to look into could be the RAG-Stiftung Foundation, which was set up to finance environmental remediation (e.g. water management and groundwater purification of former mining sites) and some of the structural transformation of the former coal mining Ruhr area in Germany (Furnaro et al., 2021). This Foundation ensures that the costs of perpetual post-mining obligations are financed when subsidized coal mining was discontinued in 2018.

Retirement-linked Green Bonds and Green Tariffs One set of tools available to utilities still running profitable coal plants and wanting to promote early retirements are green bonds or green tariffs. In either case, a standard financial tool is linked to environmental aspects to attract a lower cost of capital. There is no significant history of using these financial mechanisms to phase out coal power, but they have some potential to transition the energy sector from dirty to clean energy (Varadarajan et al., 2018).

A green bond is a standard bond linked to specific environmental outcomes. A coal retirement-linked green bond could be issued by a utility or government to support the retirement of a coal plant while linking to the historic or future coal-based emissions. A green retirement bond is like asset securitization without linking to the sale of assets on the ratepayer surcharge, thus the same cautions and caveats for asset securitization should be considered for retirement-linked green bonds. Since a retirement green bond represents a utility debt and will not be repaid by ratepayers, it is likely that the costs will be even higher than securitization. The utility could finance new RE through proceeds from the green retirement bond and swaps its coal assets for the cost of debt which is likely cheaper than its cost of capital (Varadarajan et al., 2018).

Green tariffs are a mechanism that create a special rate class or energy delivery option for large corporate buyers to ensure the energy has green or renewable origins. Retirement-linked green tariffs could allow a buyer to acquire energy that specifically replaces a retiring coal asset. The rates that the buyer pays could directly support the retiring coal asset and benefit from the lower cost of RE that replaces it. Though retirement-linked green tariffs are not yet known to be used, companies that buy them could claim rights to the emission benefits linked to their electricity fees though this method may be hard to measure and implement. A corporate buyer may have an easier time signing a Power Purchase Agreement directly with RE operators.

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Buy and Retire Managed Transition Vehicles A managed transition vehicle is an investment vehicle which is created by any investors and/or MDBs to acquire a coal asset from a utility or IPP (depending on the asset’s ownership) with the purpose of retiring it before its technical lifespan (Calhoun et al., 2021). For this mechanism to work, the investment vehicle must either have a lower cost of capital than the previous owner, and/or receive a discount for the purchase of the asset or be subsidized by a dedicated allocation of funds for the purpose of paying down the cost of climate action. The operation of the coal asset will continue realizing returns to investors and then be retired earlier than planned.

The lower the cost of capital to acquire coal assets, the faster the investors will be able to close and retire the plant. An additional advantage potentially accrues if one of the owners of the investment vehicle has some capabilities which can make the coal transition easier, such as technical and/or financial knowledge about responsible decommissioning of coal or implementing cleaner energy alternatives. Of course, the investors will also need the knowledge to continue the operation of the coal asset until its retirement, if not handled by the previous owners.

Energy Transition Mechanism The basis of an ETM is a large-scale initiative of two parts: a carbon retirement fund (CRF) to acquire and retire coal plants at an earlier pace and a clean energy fund to provide technical expertise and supplementary finance to replace the power capacity of soon-to-be-retired coal plants with RE (Kanak, 2020). While a coal plant still operates, the CRF can also find opportunities to reduce the pollution intensity of the plant during its remaining years of operation. This mechanism proposes that global or regional MDBs act as the lead shareholders of the mechanisms, adapt the CRF to the national context, and ensure that the coal plants are retired (with the CRF) and investment in renewables to replace capacity (with the clean energy fund).

The risks of this mechanism include the possibility that cash paid to coal owners through the CRF is not recycled and fed into the clean energy fund to construct and fund new RE. A robust agreement between host governments’ authorities and the implementing MDB would also need to prevent new CFPPs from being built for the sole purpose of being purchased and retired. Terms and conditions should be agreed upon with some method of enforcement or financial consequences in the case of non-compliance by either side. Additionally, there is the risk that current CFPP owners are not the most experienced or qualified

to invest in clean energy, and thus fail to manage a diversified portfolio of RE. There is also the risk that funds are not channeled to ease the transition of coal regions and coal workers, which is essential for a Just Transition.

Carbon Retirement Portfolio The idea of Carbon Retirement Portfolios is to set-up a basket of carbon assets, which are presented by Handler & Bazilian (2021) as a tool to allow investors to gather funds to directly purchase a coal, oil or gas asset with the purpose of retiring it early. They would in theory work the same way as a managed transition vehicle. Carbon Retirement Portfolios could be compared to “climate bad banks”, in the sense that the portfolio would contain assets which would face transition risks, i.e. the risks on the financial stability of asset owners due to a devaluation of assets becoming “stranded” (Daumas & Salin, n.d.). In the presentation of this financial instrument, it is explained that government support will most likely be needed to allow investors to bid competitively for the assets and incentivize the new investors to lower the amount of GHG emitted while still operating the asset. Governmental support could take the form of a ‘carbon avoidance bonus’, offering a fixed amount of money per tonne of avoided carbon.

These supports could, in principle, incentivize the retirement of assets even before the commitment date and the use of best practices to reduce emissions. However, Handler & Bazilian (2021) highlight different factors that need to be considered for this financing mechanism to work.

First, an in-depth analysis is needed to determine a carbon avoidance bonus which is reasonable: it needs to be high enough to include a wide range of assets, but not too high in order to keep it politically attractive. Furthermore, the government needs to ensure that the carbon avoidance bonus does not penalize asset investors who are already reducing the GHG emissions of their assets. One way to do so is to also offer the bonus to these asset investors as well.

Secondly, a method must exist to determine the responsibilities that need to be held by the investors of the portfolio throughout the asset’s life. Indeed, enough administrative capacity must be planned in order to ensure that due diligence is performed and to measure the GHG emissions. An official procedure must be put in place to independently verify the amount of GHG emissions avoided during the operation of the asset and due to its early retirement.

Thirdly, the amount of assets and the types of assets that the carbon retirement portfolio can efficiently manage needs to be determined.

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Lastly, a critical question to ask is where the funding of a carbon avoidance bonus would come from. If it comes from the taxpayer, this could perhaps be justified in a progressive tax system, but this could also create political and budgetary constraints on the scale of the mechanism. Making the coal user pay, as in the Indian coal cess example, may be an easier narrative to sell. Alternatively, and more radically, the bonus could be financed from the central bank by creating ‘climate capital’ on the balance sheet. The central bank could lend against this ‘climate capital’ asset base to a facility that would buy out coal assets and put them in a transition vehicle with the purpose of early retirement.

Current research on Carbon Retirement Portfolios does not indicate whether this tool could only be used by local investors or by international entities as well. Considering the government support needed to make this financial instrument viable, it should be further explored where this type of instrument could work.

Active Ownership of Coal An increasingly common practice within the investment community is active ownership, which refers to investors who use their ownership position to influence the activities and behaviour of companies within their portfolio (Piani et al., 2018).

The practice is applied across a wide range of issues, usually falling under the Environmental, Social, and Governance (ESG) umbrella. The two main ways of exercising active ownership is, firstly, through shareholder engagement, which is concerned with interactions between the investor and company with the goal of improving ESG practices and/or disclosure. Secondly, through voting to approve or disapprove of certain resolutions and practices concerning the companies in the investor’s portfolio (Piani et al., 2018). Within the context of coal, investors apply these principles to coal companies by, for example, pushing them to phase-out coal sooner rather than later.

In practice, however, the implementation of this practice is subpar. A survey conducted on 29 asset managers, representing around USD 34 trillion (EUR 30 trillion) in assets, found that only half of them have a long-term policy to phase out coal within their portfolios (Cuvelier et al., 2021). Similarly, nearly half of them have publicly stated they would use voting and shareholder engagement to achieve their climate goals.

However, few are willing to consider sanctions when insufficient progress is made (Cuvelier et al., 2021). Yet another issue is that nearly all of investors’ passive investments are excluded from coal phase-out targets and as a result only 25% of all assets in this survey fall under those targets (Cuvelier et al., 2021).

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Table 2. Comparison of financial coal transition mechanisms.

Evaluation Factor

Pay for Closure

Debt Refinancing

Buy and Retire

Grant finance or commercial product?

Grant finance, blended finance or carbon markets

Commercial debt product

Often a mixture of both, with concessional capital (e.g. low-interest rate bonds from MDBs or DIs) but can also be fully commercial

Works for public or private-sector utilities/coal-plants

Works for both, but potentially provides unfair advantages for large operators depending on contracts

Some types (asset securitization) work better for investor-owned utilities (IPPs) while others (debt restructuring) may work better for utility-owned/public utilities

Enables a just transition

Compensation is intended to cover lost future revenues of the polluter and is not necessarily bound to social uses or to pay back investors, calling into question issues of equity and fairness of this measure.

Refinancing agreements that pass on cost savings to customers must require a reinvestment in RE and support for a just transition; additional capital raised through an increased customer surcharge (ratepayer-backed asset securitization) can make resources available to coal workers and communities

Dependent conditions

Could be given (unequitably) to coal plants that are already uneconomic, but the best case would be to use compensation to incentivize money-making plants to retire early (a condition which is decreasing in prevalence over time)

Could be given (unequitably) to coal plants that are already uneconomic, but the best case would be to use compensation to incentivize money-making plants to retire early (a condition which is decreasing in prevalence over time)

Underlying business model (e.g. why this mechanism type works)

Underlying assumptions (e.g. carbon price)

Moral hazards, challenges, and risks

3

Pays coal asset owners to shut down operations, which could make up for lost future profits

The calculated carbon price of the German coal phase-out example is quite high if you include the worker and coal-dependent region compensation (goes from EUR 4.11/tCO2 to between EUR 25-42/tCO2). 3 Some argue the German government overpaid for closure Direct compensation based on lower carbon prices; untransparent assumptions can slow down the transition; oppositions to using taxpayer money to pay for a shutdown of unprofitable plants

See Annex II for detailed author calculations.

Pays off FIs and investors whose returns currently depend on the coal asset’s continued operation. The contracts and tariffs that keep CFPPs running must be up for negotiation. Coal asset owners must have an incentive to renegotiate an existing long-term contract or some opportunity to replace expected future returns from coal assets that mitigates reinvestment risk. Allows coal owners to replace ‘dirty’ profits with the opportunity to grow ‘clean’ profits. If managed well, refinancing creates opportunities for equity shareholders to reduce risk and increase earnings

Different models and mechanisms for utility-owned or IPP-owned utilities

Can include specific arrangements for worker compensation after an early CFPP closure

Must provide a lower cost of capital than the previous owner and/or receive a discount for the purchase of the asset

Cost of capital for the ‘new buyer’ should be lower than for the current owner, or there should be significant risk-taking and technological capabilities present (especially on RE technologies)

Has worked in places where carbon is not currently priced (e.g. Chile and the US). This may not be a cost-efficient option if carbon is priced higher as it is in the EU-ETS

Likely needs extra compensation like carbon credits or other incentive-based payments

Some types (ratepayer-backed asset securitization) place an extra surcharge on customers’ bills that customers will pay for now and into the future, calling into question major issues of equity and fairness.

Without enough incentives to put cashflow into RE, there is the danger of paying the polluter or creating the opportunity to wait to close in order to get a higher coal bailout price. Carbon lock-in risks if RE becomes significantly cheaper within the contractual phase-out period

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Just Transition Aspects Reflections on its meaning Aspects of a Just Transition must be included wherever talks of the energy transition occur, not just in policy discussions, but also amongst researchers, civil society members, industrysettings and social media. Unfortunately, Just Transition aspects are often left out of the conversation when discussions involve those vested interests.

For example, one should not assume that financing a fair and ambitious coal transition automatically implies a higher cost for governments or companies. Experiences suggest that failing to implement a Just Transition away from coal is more costly for governments because poorly managed transitions can leave taxpayers footing the bill for any of the following: large subsidies for uneconomic coal mines or plants, early age retirees from the coal industry, higher health-care costs due to coal mining, social security costs of high unemployment areas of coal regions or bankrupt coal companies and their unfunded liabilities (Sartor, 2018).

Financing the energy transition must mean that companies and governments ensure the establishment of a Just Transition fund “into which companies pay and/or ensuring that companies have adequate financial resources to pay for the transition of their labour force” (Sartor, 2018, p. 30). One aspect of Just Transition means wealthier countries have an important role to play in providing climate finance for developing countries to help remedy a climate crisis that they largely are not responsible for. Enabling developing countries to access international climate finance more easily and reliably must be a part of the just transition. What we see today is that donor countries are failing to provide the predictable, steady levels of funding at the required scale and that recipient countries often lack the policy frameworks and commitments which make it hard to trust that funds are going towards the right ends.

There are many Just Transition aspects that we are not able to fully address in this report, including but not limited to: the number of people employed by coal mining or coal trucking, the necessity of re-skilling and up-skilling the workforce and the use of coal in households. Their exclusion in this report does not mean that they can be ignored when climate finance engagements are made, on the contrary they should play a defining role of any formal engagements. For further considerations while making international climate finance engagements, see Figure 3 for questions and prompts that should be asked.

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Figure 3. Requirements for donor agencies to engage in a coal transition: addressing political, financial and institutional obstacles.

Assessment of coal subsidies How many subsidies does the coal sector benefit from? What is the magnitude of these subsidies? Can they be easily removed or reduced over time? Who currently depends on subsidies for the continued burning of coal?

Coal's effect on state finances What kind of revenues are generated for the government through the coal sector? How much is left after subtracting subsidies? Does coal have a positive or negative influence on state finances?

Employment in the coal sector How many people are directly and indirectly employed in the coal sector?

Who will be affected by the coal phase-out? Are there plans, supporting structures and funds set aside to help workers through the transition away from coal?

Stakeholder engagement Are the right people at the table for the coal transition discussion? This should include electricity utilities burning coal, independent power producers, government actors, ministries in the energy and industrial sectors, municipalities, electricity grid transmission and distribution network actors, civil society, civil society interest groups and labour unions, among others.

Existing coal phase-out plans What plans exist to aid society in the coal and energy transition? What do they say? Are they being followed? Are they on track?

Power sector analysis and the political economy of coal How is coal use baked into the energy sector and how is its continued use supported in society? To what extent are coal interests represented in the government and/or state?

Alternative energy sources and potential What is the uptake of renewable energies in the country? What are the barriers or obstacles to further uptake? Where can outside funding aid in the replacement of coal with renewables? Are there existing support mechanisms for renewable energy sources?

Financial absorption What is the capacity of the country to absorb more funds to speed up the transition? Are there existing international agreements or memorandum of understanding with the country to aid in the disbursement of funding to the right parties?

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3 - ECONOMICS AND POLITICAL ECONOMY OF THE POWER SECTOR IN SELECT COUNTRIES To exemplify how the financing tools presented in the previous chapter can be applied in the world, we present the context necessary before applying any one of the climate finance tools.

First presented is the motivation for choosing to perform case studies on China, Indonesia, South Africa and, briefly, India. This chapter contains the full country study for Indonesia and the

Indonesia

remaining case studies can be found in Annex I. This chapter will also provide the main lessons of these country reports in the form of a brief overview of the energy system in Table 4.

Please read the remaining full country reports in Annex I for full detail and sources.

2030 by 29% (unconditional) up to 41% (conditional) against the 2030 business as usual scenario. However, Indonesia’s current energy structure is very carbon intensive, and it requires an enormous effort to achieve a Paris-compatible structure. As can be seen from Table 3, Indonesia is heavily reliant on coal and natural gas for its electricity generation.

The case study on China was chosen to exemplify an established coal user due to the sheer magnitude of coal production and use: in 2019, China was responsible for 3,252 Mt (54.7%) of global thermal coal consumption and 576 Mt (59.5%) of global coking coal consumption (IEA/OECD, 2019). Indonesia and South Africa were chosen to exemplify coal export-oriented countries. Indonesia is a large coal exporter and the largest economy of the ASEAN nations. Indonesia’s electricity demand is set to triple by 2030, making it a large target for international efforts as a key part of the Asian coal market. South Africa was an obvious choice to study due to recent international announcements at COP26 to help South African state-owned utility Eskom reduce its debt and phase out coal, as well as the lock-in of coal in the South African power sector and the unreliability of its old CFPPs. The shorter study on the financing of coal in India and attempts to phase it out were added halfway through the research study to provide an additional perspective on another important SPIPA-member country. The analysis of India does not claim to be complete as more time would need to be invested to research this country context. This array of countries is interesting due to the wide spectrum of their status quo with respect to state-owned versus private- or investor-owned utilities, and the broader policy challenges and implications that the climate transition entails in the context of changing regional power dynamics.

Indonesia will require a fundamental transformation of its energy sector to achieve its Nationally Determined Contributions (NDCs), namely, to reduce emissions from 2020-

Table 3: Installed Capacity in Electricity Sector Indonesia (2019).

Installed Capacity (MW)

% of total

Coal

31840

50.7%

Natural Gas

16328

25%

Hydropower

4396

7%

Oil

4647

7.4%

Geothermal

1884

3%

Biomas

1696

2.7%

Wind

126

0.2%

Biogas

126

0.2%

Solar PV

63

0.1%

Others (like waste to electricity)

1696

2.7%

Total

62800

100%

Source: (Asian Development Bank, 2020a)

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Further, Figure 4 illustrates the average annual investments in the power plants, the low share of RE in installed capacity and the required structure in order to achieve Indonesias climate and energy plants (LCCP, Long-Term Strategy for 2050 and Ministry of Energy and Mineral Resources’s Net Zero Emission 2060 Scenario). The message is very clear: Indonesia needs to phase-out of coal and the financial instruments discussed above will contribute to reforms. Additionally, the framework conditions for RE needs to improve substantially, in order to build-up alternative sources of power.

Figure 4. Past investments in power sector until 2020 and the resulting and stated capacity goals.

Average Annual Investment in Power Plant 2015-2020 RENEWABLES AND NEW ENERGY

USD 1,730 million

GAS

COAL

USD 4,429 million

DIESEL

2020 (actual)

Installed Capacity (& of Total) 2050 (LCCP)

2050 (MEMR)

14%

52%

98%

29%

10%

0%

50%

38%

2%

7%

0%

0%

100%

100%

100%

Source: (Climate Policy Initiative, 2022)

According to CPI (2022) about USD 6.2 billion per annum between 2015-2020, dominated by fossil fuels, but investments to renewables increased between 2017 and 2019.

Finance from international sources, particularly from Development Finance Institutions, accounted for 65% of all finance commitments to the power sector (CPI 2022). A key turnaround in 2018, when international finance to fossil fuelbased energy sources (primarily for coal), dropped by 68% over the period 2018-2020, driven by a shift in market preference and global policy signals to align financing with Paris Agreement objectives.

At COP26 in Glasgow, the Indonesian government joined the “Global Coal to Clean Power Transition” committing to phasing out coal-fired power plants until 2040. The government also promised to retire 9.2 GW of CFPPs by 2030, with 5.5 GW planned decommissioning without replacement and another 3.7 GW planned replacement with renewables (Jong, 2021). In total, these commitments could cut the country’s annual CO₂ emissions by 89 million tonnes. According to the Indonesian government, the recent announcement to initiate Indonesia’s

coal phase-out transition is estimated to cost USD 48 billion (EUR 42.4 billion) to close the 9.2 GW of CFPPs and an additional USD 23 billion (EUR 20.3 billion) to subsidize and add the RE capacity needed to replace 3.7 GW of coal-fired power (Jong, 2021).

Although Indonesia has announced a moratorium on new coal power plant permits by 2025, it has 26 GW of coal-fired capacity in the planning or construction phase, which makes it the fifth among global leaders in terms of future coal power capacity (Figure 1), thus posing a major threat to Indonesia’s efforts to reduce its GHG emissions (Global Energy Monitor, 2021; Ordonez et al., 2022).

The government’s 2021–2030 national electricity supply plan (RUPTL 2021–2030) has set a coal capacity target of 44.7 GW by 2030, representing a 40% increase from 2020 levels (Ministry of Energy and Mineral Resources (MEMR) 2020 and PT Perusahaan Listrik Negara (PT PLN) 2021).

Renewables accounted for only 14 percent of the energy mix in Indonesia in 2020. The country still relies heavily on fossil fuels for its current energy supplies. In addition, there remain fossil fuel subsidies at an annual average of USD 135 million (EUR 119 million) since 2015, uncompetitive feed-in tariffs for renewables, a coal price cap and locked-in coal investments. The planned RE law is urgently needed in order to create better framework conditions for RE and improve the levelized cost of electricity in favor of RE.

Stakeholder Overview PT Perusahaan Listrik Negara (PLN) PLN is the main electricity provider in Indonesia. It is a state-owned enterprise (SOE) that controls virtually all power distribution, network infrastructure and sales (Asian Development Bank, 2020a). PLN also owns about 73% of power generation facilities directly and indirectly via 10 subsidiaries and it purchases around 27% from IPPs as a single buyer (Statistics PLN 2020, 2020). With over 75 million customers, PLN is one of the largest electric power providers in the world (Statistics PLN 2020, 2020). As a SOE, the Indonesian government can mandate PLN to sell energy at a regulated price to certain customers which it has done since 2017 with a mandatory electricity tariff set below break-even costs to ensure affordability of electricity (Asian Development Bank, 2020b). Due to this electricity tariff among low productivity (Annex II) PLN runs annual deficits on the order of EUR 3 billion and is reliant on annual and growing subsidies provided by the Ministry of Finance (MOF) (Annex II).

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Independent Power Producers (IPPs) After the 1997 Asian financial crisis, when the Indonesian government was essentially locked out of capital markets, private sector IPPs with project finance were the solution to developing and building capital intensive infrastructure projects. 41% of the IPPs in Indonesia are now co-owned by Chinese or Japanese investors (Hamdi & Adhiguna, 2021).

However, project finance to fund this power infrastructure required PPAs to ensure repayment to the lenders, which made PLN increasingly dependent on IPPs with restrictive PPA terms (Hamdi & Adhiguna, 2021). When President Widodo took office in 2014, the government’s overly optimistic economic targets led PLN to embrace a large demand forecast which has had long-lasting implications even today. Some suggest that IPP (foreign) investors and funders should share the burden with PLN in order to help it restructure, shed assets and reduce nearterm debt and IPP payment obligations (Hamdi & Adhiguna, 2021). Others argue that government subsidies to coal and other fossil fuels should be stopped altogether in order to level the playing field for RE and allow new IPPs providing smallscale renewables to enter the market and provide electricity to consumers (IESR et al., 2021).

Coal Mining Companies The decentralization of mining licenses in 2009 led to a dramatic increase in the number of mining permits due to revenue from land rents accruing to the district governments and the close entanglement of local politicians with coal mining operations. The glut of small mining operations has led to a variety of environmental, social and economic problems.

For example, deforestation is widespread, land management is weakly administered, post-mine rehabilitation/land reclamation is laxly enforced and illegal mining and exports are omnipresent (Atteridge et al., 2018). Therefore, Indonesia’s coal market is highly fragmented with a few large producers and many small mine owners. The market is competitive without a dominant player, which also explains why Indonesia has one of the lowest domestic coal prices in comparison to other countries (IESR, 2019b).

Financial Implications of Coal Production Indonesia is the largest global net coal exporter by volume and is mostly self-reliant for its domestic energy generation. Its coal reserves have been estimated at 149 billion tonnes, mainly on the islands of Kalimantan and Sumatra (Asian Development Bank, 2020a). Approximately 80% of its mined coal is exported overseas, mainly to China, India and Japan. About threequarters of domestic coal consumption is used for electrical power generation with the rest used by industry (mostly cement and textiles production) (Stephens et al., 2021).

The risk of shrinking coal export revenues as countries around the world move away from coal power generation is a reality which Indonesia must address. In the past, Indonesia hedged this risk by setting the Domestic Market Obligation (DMO) to ensure a minimum volume of coal purchase by domestic consumers and keep the national coal supply cheap. However, with Indonesia’s commitments to reach net zero, as other countries worldwide, the global coal transition will inevitably, at a later stage, have an impact on the economy and employment in Indonesia (Lui & Rogner, 2021). Therefore, aspects of a Just Transition should be in focus for any international efforts to aid in the phase-out of coal in Indonesia (see Box 2).

Nationally, coal mining and production contributed 1.83% to the country’s GDP in 2020 and total revenue from the coal mining sector is estimated at IDR 26 trillion (EUR 1.6 billion), of which coal is estimated at 40% of mining tax and non-tax revenues (Sumarno & Laan, 2021). The government receives further revenues from the coal sector in the form of dividends from the 100% state-owned coal company PLN estimated at IDR 3.96 trillion (EUR 245.4 million) per year and a value-added tax (VAT) on coal-based electricity consumption, estimated at IDR 1 trillion (EUR 62.0 million) per year (Braithwaite & Gerasimchuk, 2019). Local governments from coal-producing areas receive a share of these revenues through a sharing fund called the Dana Bagi Hasil.

Indonesia’s use of coal is seen as a way to “reduce poverty, promote industrialization, create domestic value and develop regions, which would otherwise lack economic perspectives” (Ordonez et al., 2022). This ‘paradigm’ of energy resources used as development capital combined with a limited public awareness of the substantial negative externalities of coal use further locks in the use of coal in Indonesia (Ordonez et al., 2022).

cer Produ Power ent Agreem

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National Energy Policy Current national energy policy in Indonesia is driven by the Kebijakan Energi Nasional (KEN) or National Energy Policy 2014 (KEN 2014), the General Planning on National Energy (RUEN) and the “Master Plan Acceleration and Expansion of Indonesia Economic Development” 4 (MP3EI). The basic strategies and objectives in KEN and KEN 2014 revolve around creating energy independence, maintaining national energy security and energy diversification, and can explain the country’s long-term energy outlook that includes coal use through 2050. RUEN, developed by the National Energy Council, sets the decarbonization targets, including the target shares for RE in the energy mix and was last produced in 2017.

Other important strategy documents which shape Indonesia’s energy policy include the National Electricity Master Plan (RUKN) developed by MEMR. The lastest version sets out electrification standards for 2019-2038 with demand and supply projections. It is used as a reference document for the Electricity Business Plan for PLN and GOI (RUPTL), which sets out Indonesia’s future capacity each year with 10-year projections

of energy demand. The 2021 RUPTL was presented as the ‘greenest’ RUPTL to date, despite predicting 13.8 GW of new coal-fired power generation capacity needed by 2030 (Draps et al., 2021). Additionally, each local government at the provincial level must have a Regional Energy Plan (RUED) stating how it plans to meet targets set forth in the RUEN. On top of these policy documents, the Indonesian government also submitted a “Long Term Strategy for Low Carbon and Climate Resilience” (2021) to the UN. In the strategy, the government details their plans to peak emissions in 2030 and reach net-zero emissions by 2060, a decade earlier than originally planned (Tao, 2021). However, this strategy is heavily critized as it plans to generate 38% of electricity from CFPPs until well into the 2050s, even increasing domestic coal mining to compensate for decreasing production elsewhere (Tao, 2021). The way that Indonesia envisions itself reaching net-zero targets is by equipping 75% of its power plants with carbon capture and storage technology by 2050, which is seen as an overly expensive technology and unrealistic (Tao, 2021).

Box 2: Just Transition in Indonesia Achieving a Just Transition is a top priority for Indonesia due to the following contextual aspects: •

The coal mining labor force (estimated at 240,000 in 2018 or 0.2% of Indonesia’s formal sector workers and 2 million jobs dependent on the coal mining industry or 1% of the working age population), especially concentrated in East Kalimantan, South Kalimantan and South Sumatra.

•

The large role of the informal economy and the urgent need to improve social protection (Błachowicz et al., 2021).

•

The geographical characteristics of the country where long coastal lines make it more vulnerable to the effects of climate change and.

•

The inequalities present in Indonesia, among others due to the vast difference in treatment between corporations and indigenous communities.

The idea of a Just Transition is more well-known among researchers in Indonesia than among policymakers and therefore it lacks a clear conceptual understanding by all stakeholders (Lui & Rogner, 2021). While the topic is starting to be discussed, this has not yet resulted in concrete policies and programs by the government. A Just Transition policy should be determined and defined in the case of Indonesia.

1

Though this planning document was unveiled in 2011 under the previous administration, some of the same vision of the MP3EI is in line with the national long-term development plan (RPJPN 2005-2025) also created under the previous presidential administration.

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Framework for Renewable Energy projects Framework conditions for renewable energy projects in Indonesia could improve, if the draft of the Presidential Regulation on the New and Renewable Energy (EBT) Bill would enter into force, as it generates fiscal and non-fiscal incentives for greener technologies (B.K.S.A.P., 2021). Among others, a feed-in tariff for small utilityscale solar with capacity below 5 MW and a competitive bidding scheme for larger solar plants above 5 MW are planned in the EBT Bill (Climate Policy Initiative, 2022).

The most important framework for RE projects is currently defined in Regulation No. 4/2020 issued by the Ministry of Energy and Mineral Resources. The regulation abolished the Build, Own, Operate, Transfer (BOOT) scheme for all types of renewable energy power plants, which project developers had to sign with PLN (Stephens et al., 2021). This can be seen as a positive development, since IPPs may now own all project assets and do not have to transfer such projects to PLN at the end of the term, thus reducing the project risk (Suharsono & Lontoh, 2020). The new regulation also provides the possibility for projects currently under development to convert from the BOOT scheme to Build, Own, Operate (BOO).

According to Climate Policy Initiative (2022), the decree also requires PLN to take renewable generation on a “must run” basis, which means that it must prioritize the dispatch of such plants against available capacity from conventional/fossil-fuel power plants. This regulation would create a strong incentive for project developers, as they can be reassured that the energy they produce will be injected into the grid.

This MEMR regulation also includes as feed-in tariff concept for different types of RE, as explained by AHK Indonesien (2020).

However, as Suharsono & Lontoh (2020) remark, Ministerial Regulation No. 4/2020 still has not addressed the major roadblock to attracting investors, which is the electricity tariff (Suharsono & Lontoh, 2020). This new regulation still uses basic electricity generation cost (Biaya Pokok Pembangkitan [BPP]), which is heavily influenced by cheap coal intake in power generation as the benchmark for electricity tariffs.

A good overview of relevant regulation in Indonesia is summarized in Annex IV of the publication from the Climate Policy Initiative (2022).

Grid Capacity The Indonesian government has a goal of 100% national electrification, but by the end of 2019 it had achieved 98.9%. The last households to connect will be the costliest as they are the most remote and the island structure limits easy connections.

The MEMR has predicted an average annual increment of 6% in national energy demand. To keep pace with the increased demand, PT PLN, the sole operator of transmission and distribution in Indonesia, needs to ensure a well-integrated electrical system throughout all geographical areas. However, based on historical investment in transmission and distribution infrastructure by PT PLN, the average annual investment in electricity networks in Indonesia leveled off in 2019 and stood at USD 1.4 billion (EUR 1.2 billion) (Climate Policy Initiative, 2022).

Additional transmission and distribution lines are also needed to support the future development of utility-scale new RE projects and smart grid projects in Indonesia and will be especially important in Eastern Indonesia. ADB is currently supporting this effort with a USD 600 million (EUR 530 million) loan in the Electricity Grid Strengthening-Sumatra Program (Asian Development Bank, 2020a). Others also predict that Indonesia’s grid capacity will need to expand to support trading and transfer between grids to reduce peak loads (IESR et al., 2021).

While the state has a legal monopoly on transmission and distribution, the Asian Development Bank sees an opportunity for private investment in the unregulated, decentralized, mainly off-grid distribution options in rural electrification and microgrids to achieve universal electrification (Asian Development Bank, 2020a).

Incentives that impact levelized costs of electricity For our analysis of the levelized cost of electricity it is also important to analyse standards, subsidies and taxes that disturb the energy sector and impact the costs of producing RE compared with coal.

Local Content Requirement The Ministry of Industry’s (MOI) Regulations No. 54/2012, No. 4/2017 and No. 5/2017 set minimum thresholds for domestically produced materials and services of solar power generation to support local industries and job creation, called the Local Content Requirement (LCR) (World Bank, 2021). In 2019, the LCR was 60% for solar PV modules (IESR, 2019b).

Local production of solar PV panels in Indonesia has been unable to scale up its production, resulting in solar PV panels of lesser quality with higher average prices relative to the international market. For example, in 2019 Chinese solar modules ranged between 0.1-0.3 USD (EUR 0.09-0.26)/Watt peak, while Indonesian prices ranged from 0.3-0.4 USD (EUR 0.26-0.35)/Watt peak (IESR, 2019b).

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Emission Standards Indonesia has one of the weakest emission standards for CFPPs in the world with loose norms for SO2 and NOx emissions when compared to developed and even to large emerging economies such as India or China (Bhati & Singh, 2017; Gallagher et al., 2021).

The government has several nationwide policies in place that technically regulate emission standards for CFPPs but these are not consistently enforced (Gallagher et al., 2021). To date, there are no performance standards or policies targeting reducing GHG emissions from power plants.

Subsidizing Coal and Coal Price Cap Fossil-fuel subsidies in Indonesia utilized about 6% of the total state budget as of 2020, a value which is consistently higher than climate-related expenditures in the country (Mafira, 2021).

Annual fossil-fuel subsidies are estimated at USD 8.6 billion (EUR 7.6 billion), of which USD 4.3 billion (EUR 3.8 billion) subsidize energy, most notably electricity, mostly for small households and businesses (Fakih & Brézillon, 2021).

BAPPENAS, Indonesia’s Ministry for Development and Planning, calls for a complete phase out of fossil-fuel subsidies by 2030 in its National Medium-Term Development Plan for 2020-2024 and the installation of a carbon price to lower emissions (A Green Economy for a Net-Zero Future: How Indonesia Can Build Back Better after COVID-19 with the Low Carbon Development Initiative (LCDI), 2021; The National Medium-Term Development Plan for 2020-2024, 2020). Joko Widodo, the current president of Indonesia, has had some success of rolling back fossil-fuel subsidies (from 3% of GDP to 1%) between 2014 and 2016.

However, in 2018, the MEMR introduced a coal price cap. Since then, coal miners must sell at least 25% of their supply directly to PLN at the domestic coal price cap of USD 70 (EUR 62) per tonne 5 which keeps the price of energy low for consumers and effectively further incentivizes the continued use of coal (Asian Development Bank, 2020; Mafira, 2021). The coal price cap essentially reduces cost pressure on PLN by shielding it from the impact of a rise in international coal prices and is largely a cost borne by the coal mining industry (Bridle et al., 2019). Aside from these direct operational cost subsidies for PLN, the coal sector also benefits from unquantified tax breaks, royalty advantages, debt guarantees and business viability guarantees, further inflating the ‘security’ of coal use (Braithwaite & Gerasimchuk, 2019).

Electricity Consumption Subsidies Though subsidies for electricity consumption aim to benefit poorer households, wealthier households disproportionately benefited from the country’s fossil fuel subsidies due to higher

5

energy consumption through regulated low prices for fossil fuels and electricity. Despite adjustments to the electricity classes in 2015 to benefit poorer households, the well-off still disproportionately benefit the most from electricity subsidies, most of which is produced from coal (OECD Peer-Review Team, 2019).

Though electricity subsidies were cut between 2014 and 2017, the government decided again to shield citizens from rising global oil prices and PLN from financial burden when subsidies were increased in 2018 (OECD Peer-Review Team, 2019). From the government’s COVID-19 relief, PLN received USD 3.2 billion (EUR 2.8 billion) and poor households received USD 912 million (EUR 805 million) for energy subsidies mostly in the form of discounted electricity tariffs (Sumarno & Sanchez, 2021). Indonesia has also continued its yearly electricity support subsidy totalling USD 6.8 billion (EUR 6.0 billion) of which USD 3.4 billion (EUR 3.0 billion) went to electricity subsidies (Sumarno & Sanchez, 2021).

Carbon Tax in Indonesia In his most progressive effort to reduce carbon emissions, the Indonesian President announced a “Regulation on Carbon Economic Value Instruments” in 2020 to introduce an Emissions Trading System (ETS), results-based payments and a carbon tax (Sumarno & Laan, 2021). In October 2021, the Indonesian Government passed Law No. 7/2021 on the harmonization of tax regulations to introduce a new carbon tax in the form of a cap and tax scheme, a tax imposed on carbon emissions beyond a determined cap (Simatupang et al., 2021). The tax will be piloted in CFPPs beginning in April 2022. The government plans to expand the carbon price to other sectors beyond coal-fired power generation and establish an economy-wide ETS, starting in 2025.

The carbon price will be set at the rate of IDR 30/kgCO₂e or EUR 1.88/tCO₂e, which will be among the lowest carbon pricing rates in the world (Simatupang et al., 2021, World Bank 2021).

The Indonesian Taxation Analysis estimates a potential revenue of IDR 6.5 trillion (EUR 402.7 million) from the carbon tax in the power sector alone (Simatupang et al., 2021). This value would increase over time as more sectors are included in the tax. Revenues from the carbon tax can be allocated towards climate mitigation (Ibid) or adaptation efforts, but no evidence of allocation has been yet presented. Skeptics of the tax argue that it could adversely affect the poorest citizens and make electricity unaffordable for them. Others stress that with continued fossil fuel subsidies and without proper measures in place, the government may be tempted to increase subsidies to offset the cost of the carbon tax if passed on to customers. Some claim that the carbon tax is too low to cause any significant change for coal operators, especially as long as the DMO and PPAs are still in effect.

Market prices of coal since 2018: 01/2018 – USD 100 (EUR 88)/tonne, 01/2019 – USD 99 (EUR 87)/tonne, 01/2020 – USD 97 (EUR 86)/tonne, 01/2021 – USD 83 (EUR 73)/tonne, 01/2022 – USD 168 (EUR 148)/tonne, 03/2022 – USD 422 (EUR 373)/tonne (Trading Economics, 2022)

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The Levelized Cost of Electricity The levelized cost of electricity (LCOE) is a standard tool used to compare the cost of different electricity generation technologies. It is a measurement of total cost and energy/electricity generated by an asset over its lifetime. The calculation results in a single value that represents each technological option available in a particular location. The single value can be easily compared and therefore can help to find the ‘cheapest’ source of energy generation for a certain place.

LCOE calculates the total cost occurred during the lifetime of an electricity generation plant and divides it by the total electricity produced during the lifetime. In the Annuity Method, the total cost accounted will be converted into an equivalent annual cost and the electricity generation value used is the average annual electricity generation.

Our analysis that follows is based on IESR (2019), Esser et al.

(2021) and the IESR LCOE tool IESR (2019a). Figure 5 provides an overview of LCOE for different technologies in Indonesia:

According to IESR (2019b) the levelized cost of of supercritical coal lies at 5.77-8.05 USD/kWh (5.09-7.10 EUR/kWh) in 2019 (IESR, 2019b). The following distortions contribute to this low level in Indonesia:

20 Onshore Wind

ct/kWh

16 14

OCGT

12

12.04

10 8 6

9.2

16.1

OCGT

8.93 6.69

Coal Mine Mouth

8.41 7.31 5.01

4

Utility Scale Solar

Coal Coal Coal Ultra Sub Super Critical Critical Super Critical

6.11

8.05

8.38

5.77

5.03

Biomass Geothermal

11.4

10.28 8.7

7.39

Variable OPEX is the most relevant case for Indonesia because we found most market distortions relevant for this cost factor.

As REs do not need fuel, any changes in fuel prices do not impact the LCOE of RE. However, it is obvious that the price of coal is a relevant OPEX variable. IESR (2019b) calculate the following sensitivity: a 20% increase in OPEX costs increase LCOE against a baseline-scenario and thus will increase the LCOE of fossil-fuels by up to 18%. In other word: reducing coal caps, imposing a strict carbon tax, etc. will increase the production costs of coal energy, thereby improving the competitiveness of RE.

Market distortion affecting low LCOE for coal power plants

Figure 5. Levelized cost of renewables and fossil power plant in Indonesia in 2019 18

In general, the higher the CAPEX, the higher the LCOE. This effects the LCOEs of RE negatively, as these technologies are more capital intensive compared to conventional technologies. IESR (2019b) calculates the following sensitivity: a 20% decrease in CAPEX will lower RE LCOE from 15-20%, while the similar change will only affect coal and gas LCOE by 5.5-9.5%. In other words: reducing capital costs, e.g. by offering concessional loans or guarantees, will improve the competitiveness of RE.

5.84 4.56

4.68

2 0

Source: (IESR, 2019b)

As our analysis above has shown, the costs for certain energy sources are highly distorted in Indonesia due to market distortion factors that we will explain in the next sub-section. We will discuss how the picture might change if distortions would be considered.

Distortion can occur on CAPEX (equipment costs, installation costs) and OPEX, whereas OPEX can be divided into variable costs (especially fuel costs) and fixed costs (costs that occur regardless of operating outcome, e.g. land lease). More obvious are distortion on OPEX, e.g. when coal price does not reflect market price, as Indonesia imposed a Coal Cap. OPEX might be disturbed when financing institutions consider a certain technology as more risky, than other technologies and impose an additional risk-premium on the interest rate. We will explain in more detail below how this especially effects RE technologies.

Coal Cap: coal miners must sell at least 25% of their supply directly to PLN at the domestic coal price cap of USD 70 (EUR 62) per tonne. At the same time, world market prices have mostly stayed above that value since 2018 (Trading Economics, 2022; see Footnote 5), implifying a subsidy for coal-energy producers (OPEX impact).

Carbon Tax: the carbon tax clearly works in contrast to the Coal Cap, imposing additional cost to coal-energy producers (CAPEX impact). As mentioned above, the carbon price in Indonesia is to be set at the rate of IDR 30/kgCO₂e or EUR 1.88/ tCO₂e, which will be among the lowest carbon pricing rates in the world (OPEX impact).

State subsidy for loss-making PLN of above EUR 3 billion per year. This subsidy imposes a type of public guarantee for capital providers, so that financing institutions consider PLN risk as lower than under a scenario without subsidy. Consequently, an additional risk-premium on the interest rate is not applied.

PLN has a 40% debt share (60% equity, see Annex II), so the mechanism should be realistic (CAPEX impact).

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Emission standards: Low standards is a sign of outdated technology. In case of stricter laws and more enforcement, additional investments into equipment and installation would be necessary, directly impacting CAPEX.

Market distortion affecting low LCOE for RE plants According to IESR (2019b) the levelized cost of of utility-scale solar power lies at 5.84 - 10.28 USD/kWh (5.16 – 9.08 EUR/kWh) and for wind in the range of 7.39-16.01 USD/kWh (6.53 – 14.14 EUR/ kWh) (IESR, 2019b). The following distortions contribute to these high levels - in comparison to coal - of the LCOE of RE in Indonesia: Local content: In 2019, the LCR was 60% for solar PV modules.

The current global market price of the Chinese module ranges from 0.1 to 0.3 USD/Wp, while Indonesian prices are in the range of 0.3 - 0.4 USD/Wp (IESR, 2019b). Accessing module price at global market price would decrease the solar LCOE up to 50% (4 - 8 USD/ kWh, IESR, 2019b). This level of cost, which is on par and even lower than coal LCOE, would trigger more solar PV development.

Feed-in tariff: Current feed-in tariffs are not transparent and are based on basic electricity generation cost (Biaya Pokok Pembangkitan [BPP]), which is heavily influenced by cheap coal intake in power generation as the benchmark for electricity tariffs. The lower the feed-in tariff, the higher the LCOE (OPEX impact). Unfortunately, the IESR LCOE tool does not model different feed-in tariffs yet, though an update to this model is due mid- to late-2022 according to a RFP from IESR to improve and update the LCOE tool.

Thesis 1: Reducing financing costs for RE and eliminating state guarantees would improve their competitiveness vis-à-vis conventional technologies.

To reduce LCOE for RE projects and make this technology more competitive, especially CAPEX costs must be considered. As RE projects are more capital intensive, incentives that reduce capital costs are an important element to raise their competitiveness vis-à-vis conventional technologies. Therefore, we believe that especially long-term concessional loans could be an important financing tool that contribute to this effect. Guarantees are relevant for RE project developers because they will reduce the risk-premiums that banks calculate. The same applies for longterm PPAs (that also influence OPEX costs): financing institutions value long-term PPAs as risk-reducing financing instruments, therefore such PPAs also effect LCOE. The implicit guarantee of the Government of Indonesia, which annually provides a EUR 3 billion bail-out to PLN, distorts the LCOE of coal.

Reducing or eliminating this instrument would therefore also improve the competitiveness of RE vis-à-vis conventional technologies.

Thesis 2: Indonesia needs to work on the true costs of coal in order to improve the competitiveness of RE vis-àvis conventional technologies.

Coal caps, coal subsidies, and the low value of the CO₂ tax impacts OPEX and therefore the LCOE of coal. Eliminating the negative incentives (caps and subsidies) and bringing domestic coal prices more in line with an international level would therefore also improve the competitiveness of RE in Indonesia. As a positive side effect, it would also free public budgets, that could then be used for more sustainable investments. A more ambitious carbon-tax would, in addition, eliminate negative external effects, like CO₂-emissions, health impacts, etc.

Thesis 3: Implementing sectoral reforms in Indonesia’s energy market needs to be accompanied by the Just T ransition.

If Indonesia wants to achieve its NDC target, a sectoral reform of its energy market is essential, especially the retirement of coal production. This will directly affect Indonesia’s largest energy producer PLN, that has been accumulating large amounts of budget deficits over many years. This will also affect many coal mining suppliers, that are concentrated in a few areas of Indonesia and are often linked to the informal sector (with low income). These and other contextual aspects (discussed in Box 2) imply the need for any reforms to be accompanied by Just Transition aspects, in order to gain political and social support.

Thesis 4: Framework conditions for RE projects need to be improved to raise especially private capital.

The long-awaited renewable energy (EBT) law in Indonesia could improve the framework conditions for RE, as it contains among others feed-in tariffs, auctions, and dispatch orders. If designed well, it creates the necessary conditions, that the private sector – foreign and domestic – needs to have the confidence in investing in such sectors. Countries like Brazil have demonstrated that good regulations (in this case an auction scheme) changed the RE world in a short timeframe. As of today, development finance institutions can play an important role in mobilizing private capital. Innovative finance approaches, like the green sukuk, green bonds, and other sustainability-linked bonds can act as a potential instrument to channel significant volumes of capital into renewable energy.

Thesis 5: Development Finance Institutions will play a crucical role to finance the structural reforms and a regulatory framework will push them to invest in greener assets.

Development Finance Institutions played an important role in the past in financing the power sector, however they invested in conventional technologies. Their role will be important in the future, as private investors might need a DFI as a co-investor or long-term debt financier to build confidence into this new market.

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International and national framework conditions are supportive to this trend: Indonesia’s new taxonomy, international disclosure frameworks, pressure on DFIs to align their portfolio with SDGs and climate targets on the one hand and the risk to invest in stranded assets on the other hand will push them to invest in greener assets.

Thesis 6: Financial instruments presented in the study might not be sufficient, to achieve a complete coalphase out in Indonesia.

The Asian Development Bank will introduce the Energy Transition Mechanism and Indonesia will be one of the pilot countries. Although well developed, the instrument might not be sufficient to finance a complete coal-phase out. The instrument is targeted at the debt-side of the power sector. PLN balance sheet shows a very large equity share (nearly 60%), so additional instruments of stock buy-out or other innovative mechanisms of shareholder engagement might be necessary and “old instruments” like debt-for-climate or debt-for-nature swaps might be applicable in order to initiate a broader transition in Indonesia.

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Table 4. Characteristics of the energy sector in four countries with a focus on the role of coal.

6

Characteristics

China

India

Indonesia

South Africa

Share of coal in the electricity mix

64% (IEA, 2021a)

76% (IEA, 2021a)

63% (IEA, 2021a)

88% (IEA, 2021a)

Share of RE in the electricity mix6

28% (IEA, 2021a)

17% (IEA, 2021a)

17% (IEA, 2021a)

7% (IEA, 2021a)

Role of SOEs in the electricity mix

61% of coal capacity is entirely state-owned, and another 33% is mostly state-owned (Hervé-Mignucci, 2015)

Nearly 55% of CFPP owned and operated by SOEs (Pai, 2021b)

64% of energy produced

by PLN (SOE) (Statistics PLN 2020, 2020)

100% of coal capacity is owned

by Eskom (SOE) with the exception of some emergency capacity provided

by IPPs (Eskom, 2021)

Debt level of SOEs in the coal sector

Data not available

State owned distribution companies have high debts and require financial bail-out (Suri et al., 2021)

0.7 debt ratio (Annex II)

Organization of the coal mining sector

20 companies account for 61% of coal production (2017), further centralization because of measures to reduce production overcapacity (H. Zhang, 2021)

93% of coal produced by three largests SOEs, of which 81% by Coal India Limited. 60% of produced coal is transported by SOE Indian Railways (Pai, 2021b)

Highly fragmented: over-issuance of mining licenses, non-compliance with coal mining moratorium & corruption issuing permits (Arinaldo & Adiatma, 2019)

Five companies account for 85% of coal mining (Department of Mineral Resources and Energy, n.d.)

Role of unions

Weak, no independent unions permitted outside the All-China Federation of Trade Unions (ACFTU) (Huld, 2022)

Multiple trade unions, active role in formulating a just transition and ensuring welfare measures.

(Roy et al., 2019)

Mostly aggregated in Indonesian Coal Mining Association (APBI), impact unclear (APBI-ICMA, 2022)

Important, cooperation of all labour unions in COSATU, as well as an alliance with the ruling party (Hanto et al., 2022)

Share of mining employment in total economy employment

0.003% (calculation based on CEIC, 2021

0.26% (calculation based on employment numbers Pai, 2021b)

450,000 (2018) or 0.004% of total workforce (Arinaldo & Adiatma, 2019)

0.9% (calculation based on Garside (2022) and Moody’s Analytics (2021))

Average age of coal-fired power plant fleet

14 years (Myllyvirta et al., 2020)

13 years (Brunetti, 2020)

12 years (Isaad, 2021)

42 years (calculation based on Eskom (2021))

Coal’s contribution to state revenue

Data not available

Revenue of Coal India Limited is INR 938 million (EUR 11 million) in 2021

1.5 - 2.5% of GDP (Arinaldo & Adiatma, 2019; Atteridge et al., 2018)

1.0 – 1.3% of GDP (Bridle et al., 2022)

Government support to RE

Phase-out of direct subsidies, however provision of tax breaks and low-interest loans for renewable buildout (including grid improvement) (Lin, 2022)

Increasing RE targets, enacting stronger pollution regulations for thermal power plants, and encouraging RE with policy support (Wetherbee et al., 2022)

RE law still being discussed by the government (Ministry of Energy and Mineral Resources, 2021)

Successful procurement programme for RE (REIPPPP) (Hanto et al., 2022)

Energy security concerns

Power rationing during coal shortage in autumn 2021 have renewed energy security concerns (Lo, 2022)

Energy poverty & relatively low access rates to grid (Dubey & Lakhanpal, 2019; Montrone et al., 2022)

High access to electrification (around 96.7%) (Statistics PLN 2020, 2020)

Frequent load-shedding and blackouts, energy poverty, big price increases (Geddes et al., 2020)

Grid improvements needed

Ultra-high voltage buildout underway, however not yet sufficient (Ye & Yuan, 2021)

Need for technically resilient and reliable grids.

Distribution companies struggle to integrate RE in national grid (Suri et al., 2021)

More interconnections, modernization & integration needed between islands (Asian Development Bank, 2020a)

Increase generation; modernization; expansion of transmission and distribution, with special focus on micro-grids (Eskom, 2021; The World Bank, n.d.)

Includes hydropower, geothermal, biofuels, wind, solar PV, solar thermal, tide, and waste power

3.4 debt ratio (Annex II).

Heavy government support on a yearly basis, of around EUR 3 billion (Eskom, 2021).

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CONCLUSIONS AND FUTURE RESEARCH Main findings from this research study: This study found that not many financing tools already implemented aimed at engaging in the global or regional coal phase-out. This suggests there is space for new financing initiatives which aim to achieve a just coal transition, especially in non-OECD developing countries which may be struggling to finance their own coal phase-out due to the unforeseen rise of debt levels and/or overall financial crisis caused by the COVID-19 pandemic.

Most of the financing mechanisms described in this study are not in line with a “polluter pays” principle as most transfer money to coal asset owners in exchange for a coal phase-out. This is especially unjust when the money comes from public funds. While the massive social and environmental benefits of a coal phase-out could arguably justify breaking the “polluter pays” principle in some cases, the biggest danger of employing mechanisms that benefit the coal industry is that compensation (in any form) for coal phase-out could become normalized and expected. This could inadvertedly slow down the coal phase-out even further.

There is the risk that current coal asset owners are not the most qualified to invest in clean energy, and thus fail to manage a diversified portfolio of renewable energies, or they lack the will to reinvest in clean energy. There is also the risk that not enough funds are channeled to ease the transition of coal regions and coal workers, which is essential for a Just Transition. These risks should be a key concern for international investors to consider when choosing financial or policy instruments which give any concessions to coal asset owners.

The case studies show that one of the main obstacles to a faster coal phase-out is the financial interests at stake in coal power plants.

Defining who loses their investments and defaults on their loans is one core issue that needs to be addressed to accelerate the phase-out of coal. Another large obstacle identified from the case studies is the entanglement between coal power companies (especially those that are state-owned) and political leaders as shown in Indonesia and South Africa. Additionally, economic forces and stimuli, such as a lower levelized cost of renewable electricity, are not enough to phase-out coal due to heavy government intervention into markets (e.g. coal subsidies, LCRs, etc.) and a lack of RE-favorable policies (e.g. feed-in-tariffs). We conclude that if the socio-political barriers are so high to prevent the coal phase-out from happenning naturally, then a bail-out of polluters may be justified as necessary.

Suggested future research topics: •

eveloping a research and political agenda to create a guiding set of principles or philosophy of who should pay for what via a D “polluter pays” principle embedded into how to finance a just coal transition. International climate finance will play a role, but the nuance of this report demonstrates that money cannot be a replacement for national ownership of the just transition.

•

n issue that is under-explored and under-addressed: engaging internationally with the economics & financing of the supply of A coal and shutting down coal mines

•

Modeling of the true LCOE for each energy source in specific countries to see how coal really competes with RE

•

Using the financing mechanisms presented in this study, discuss and engage with policymakers, financiers, and coal asset owners in target recipient countries to determine which options are actually viable in those contexts

•

Phasing out coal in industrial sectors, which can be much more difficult than a coal electricity sector phase-out.

Outlook and recommendations: •

e challenge OECD countries to evaluate the ethics and equity of compensation mechanisms and debt refinancing mechanisms W that use taxpayer money to fund the coal transition.

•

I t is clear from our workshop with EU COM that policymakers need more information on the political economies of coal in specific countries before they get engaged. More research should look into what policymakers need to make the best decisions regarding how to engage internationally.

•

olicymakers should take these broad findings and points of nuance to carefully consider the best options regarding how to P phase out coal.

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ANNEX I – COUNTRY CASE STUDIES

This Annex investigates the structure of the power sector in the remaining case study countries as an exemplification of the different factors that can influence the political economies of coal phase-out in different contexts. Each section will include the following: the ownership structure of coal, technological/ environmental standards, the governance structures over the use of coal, the influence of fossil-fuel subsidies on the use of coal and how climate finance can work to reduce the dominance of coal-fired power capacity in economies given the complex context of each country.

China

The share of coal in the Chinese electricity mix dropped to 60% in 2020. Total electricity production from coal has kept rising, albeit at a slower rate than in the early 2000s and reached 4623 TWh in 2020 (Figure 6).

Figure 6. Electricity production from coal in China is still rising, but growth has slowed Electricity production by source, China

Our World in Data Other renewables Solar

7,000 TWh

Wind

6,000 TWh

Hydropower

5,000 TWh

Nuclear Oıl Gas

3,000 TWh

„ At present, coal is the energy source that we can truly rely on ourselves for supply. It will remain so for quite a long time to come, and this bears on China‘s development “ Premier Li Keqiang, November 2021 China is the largest coal producer in the world, accounting for 50.7% of global production in 2020 (BP & Ember, 2022). Coal production is highly concentrated in the provinces of Inner Mongolia, Shaanxi, Shanxi and Xinjiang, which together account for 79% of Chinese coal production (Gosens, 2021).

Due to a shortage of domestic coal transport infrastructure, domestic coal is uncompetitive especially in coastal provinces in the South, where steel and power plants often have port facilities but no railway connections (Gosens, 2021). These factors led China to import 7% of its thermal coal and 13% of its coking coal consumed in 2019 (Gosens, 2021). These amounts make China the world’s single largest importer of coal, accounting for 223 Mt (21%) of global thermal coal imports and 75 Mt (24%) of global coking coal imports (IEA/OECD, 2019).

While 48% of coal is used to generate thermal power, 39% is used in industry. Heating supply, buildings and agriculture together make up 13% of coal use (Zhou et al., 2020).

Coal

2,000 TWh 1,000 TWh 0 TWh 1985

1990

1995

2000

2005

2010

2015

OurWorldInData.org/energy - CC BY

4,000 TWh

2020

Source: Our World in Data based on BP Statistical Review of World Energy & Ember (2021) Note: ‘Other renewables’ inclues biomass and waste, geothermal, wave and tidal.

In September 2020, Xi Jinping informed the UN General Assembly that China would aim to peak its carbon emissions before 2030 and reach net zero by 2060 (McGrath, 2020). This policy goal is ETS, also referred to as “double carbon” (双碳). A year later, Xi Jinping announced that China, which was responsible for funding twothirds of all planned coal power capacity in Asia outside of India and China (Suarez & Gray, 2021), would stop building new CFPPs abroad (Volcovici et al., 2021).

However, in 2021 alone, China added 25 GW of coal power capacity to its grid and began construction on a further 33 GW, which is in both cases considerably more than in the rest of the world (Myllyvirta, 2022). While the permitting of new coal projects was essentially stopped in 2021 due to an emphasis on emissions control, the first six weeks of 2022 saw the approval of five coal power projects with a combined capacity of 7.3 GW. Even with plant retirements, coal power capacity continues to increase in China, while it falls in the rest of the world (Myllyvirta, 2022). On the other hand, China is simultaneously also rapidly increasing its renewable capacity, with an addition of 134 GW of RE to the grid in 2021 (Lin, 2022) 52

Stakeholder Overview

Chinese Power Sector

National Development and Reform Commission (NDRC) The NDRC is responsible for economic planning, which crucially includes determining wholesale and retail benchmark electricity prices for provinces (H. Zhang, 2021). It also prepares the national Five-Year Plans. The NDRC established the pilot phases of the Chinese ETS, until the responsibility was passed to the newly established Ministry of Ecology and Environment (MEE) in 2018 as part of government (International Carbon Action Partnership, 2019).

In 2002, China unbundled the state-owned State Power Corporation into two state-owned grid companies (China State Grid and China Southern Power Grid) as well as five state-owned generation companies. These five SOEs, also referred to as the ‘big five’, are State Power Investment Corporation (SPIC), Huadian Group, Datang GroPICup, Huaneng Group and China Energy Investment Corp (CEIC)7 . Together, these companies own 46% of installed coal power capacity in China.

National Energy Administration (NEA) The NEA is subordinated to the NDRC and charged with energy policy planning, co-ordination and implementation (H. Zhang, 2021). Together with the NDRC, it established the ‘traffic light’ system for coal overcapacity risk in 2016 (Springer et al., 2022).

Ministry of Ecology and Environment (MEE) The MEE, known as the Ministry for Environmental Protection prior to 2018, is responsible for setting China’s environmental policies, which also includes its climate change policy. It also established the Chinese national ETS, which started operating in 2021.

Subnational Governments While China is often perceived as a highly centralized country, the implementation of its policies is often highly fragmented. This is the case with its energy policy too, as described in this case study.

Due to performance of provincial governments being assessed based on economic indicators, they are incentivized to invest in expansion of coal production and power generation, which conflicts with environmental targets (van der Kamp, 2021).

State-owned Assets Supervision and Administration Commission of the State Council (SASAC) SASAC is responsible for managing central SOEs, including the ‘big five’ power generators and two grid companies.

State-owned enterprises (SOEs) In addition to the two grid companies in China being entirely state-owned, 61% of China’s installed coal power capacity is state-owned, with an additional 33% being mostly state-owned (Hervé-Mignucci, 2015). While SOEs generally operate separately from the state budget and are run like private firms, they benefit from policies such as preferential access to bank capital and lower loan rates (Hervé-Mignucci, 2015). Central SOEs are owned by SASAC but key management teams are nominated by the central organization department of the Chinese Communist Party.

7

A 2015 report estimated the 2013 share of SOE ownership of China’s installed coal power capacity at 61%, with an additional 33% being mostly state-owned (Hervé-Mignucci, 2015). This includes the big five SOEs as well as other central and provincial SOEs. The coal production (mining) sector is not quite as concentrated as that of coal power generation, with 20 companies accounting for 61% of coal production in 2017 (H. Zhang, 2021). Most of the Chinese energy sector is vertically integrated, where coal power producers are also involved in the mining of coal (OECD, 2016).

As the following section will explain, however, various policies that incentivize investment in coal power have led to the Chinese power sector becoming characterized by overcapacity.

The Issue of Overcapacity Policies contributing to the development of overcapacity Many factors have contributed to the development of overcapacity in China. First, investment in coal power is incentivized by the Electric Power Law of 1995, which introduced a guaranteed return on investment through regulated electricity tariffs for each CFPP (H. Zhang, 2021). Additionally, whereas most other countries give priority to power produced at the lowest marginal cost, China has an equal dispatch rule, which allocates similar operating hours to all coal-fired generators (Ren et al., 2019; H. Zhang, 2021). Due to these mechanisms, there was initially little incentive for plant operators to control costs. As a remedy, a benchmark price was introduced in 2003, which set a uniform electricity tariff for all coal power plants within a province.

This allows operators to increase their profit margin by reducing production cost (Ren et al., 2019).

As a result of restructuring in 2017 – 2018, SPIC emerged from a consolidation of generation company China Power Investment (CPI) and the State Nuclear Power Technology Corporation, and CEIC emerged as a result of coal mining company Shenhua acquiring generation company Guodian.

53

However, most of today’s overcapacity is a direct result of the expansion driven by the 12th Five-Year Plan for 2011-2015, which was formulated as a response to the global financial crisis and called for a massive expansion of coal projects to boost economic development (Myllyvirta et al., 2020).

Additionally, the 2014 shift of the authority to approve coal power plants from the central government to provincial governments resulted in shorter and cheaper approval processes and contributed to capacity expansion (Ren et al., 2019). Since provincial government officials are evaluated based on economic indicators, they are incentivized to approve superfluous coal-fired plants that provide additional tax income and employment, especially in coal-rich regions (Springer et al., 2022).

In 2015, 210 coal power plants with a combined capacity of 169 GW were approved (Myllyvirta et al., 2016), despite decreasing coal consumption overall (H. Zhang, 2021). This means that most of the Chinese coal fleet is very young: 43% of Chinese coal power capacity was under 10 years old in 2018, with less than 4% being older than 30 years (Table 5).

Historically speaking, however, Chinese CFPPs have an average lifetime of 24 years until they are retired, much lower than the global average of 50 years (Cui et al., 2019) This is a result of efforts to shut down small, more-polluting units to improve air quality (Cui et al., 2012).

Overcapacity in China has led to decreasing operating hours of thermal power plants as well as curtailment of renewables (Ren et al., 2019). As a result almost 50% of Chinese thermal power generators were operating at a loss between 2018 and 2019 (Gao, 2020).

The tension between generation companies seeking low-cost fuels due to regulated residential energy tariffs and coal miners wanting to sell their product at a higher price have resulted in increasing vertical integration in the coal power sector to prevent bankruptcy, driven by SASAC (Springer et al., 2022).

Table 5. Age of installed coal-fired capacity in China.

Age (years)

Capacity (GW)

% of Total

0 - 10

428

43%

10 - 20

420

43%

20 - 30

102

10%

31+

38

4%

Total

988

Source: (IEA, 2020a). Appears in: CCUS in Clean Energy Transitions, Informed

by S&P Global Platts (2020), based on fossil power plants in operation in 2018.

Policies to reduce overcapacity Starting in 2016, the Chinese government began introducing policies to deal with overcapacity targeting both the upstream sector (coal production) and the downsteam sector (power generation).

Notably, on March 27 2016, the NDRC and NEA introduced a ‘traffic light’ system, which assesses the risk for coal overcapacity in China’s provinces for the next three years. This means that in 2022, the risk for 2025 will be assessed. A red or orange light on the capacity adequacy indicator essentially prohibits these regions from approving or starting construction on any new coal power projects (Gao, 2020). However, while in 2016, only two of China’s 31 provincial grids received a green light for 2019, in 2020 the policy forsaw green lights for 25 provinces in 2023, allowing these provinces to approve new coal projects (Myllyvirta et al., 2020). This system has been criticized for being intransparently calculated and for failing to take into consideration other factors such as the role of transregional grids and demand response (Gao, 2020).

In the mining sector, measures to eliminate overcapacity of coal production have led to the closure of mainly smaller and local mines, resulting in a recentralization of production capacity from provincial SOEs and private firms to central SOEs (H. Zhang, 2021). In the “Opinions on Addressing Overcapacity and Achieving a Turnaround in the Coal Industry” issued in 2016, the State Council proposed the reduction of one billion tonnes of production capacity. While the target was later adjusted to 800 million tonnes, progress has been made in terms of reducing overcapacity in coal production. However, this has not yet led to a decrease in total coal production (H. Zhang, 2021). A moratorium imposed on new coal mines in 2016 was lifted in 2018 to ensure coal supply at a reasonable price (H. Zhang, 2021).

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Box 3: Coal Combustion Efficiency In subcritical power plants, with traditional combustion technology, the steam pressure and the temperature generated does not exceed the so-called critical point of water at 374°C and 22.064 MPa (Hart et al., 2017). They have an average efficiency of 36%, meaning that 36% of the energy in the coal used is converted into electricity. Supercritical plants are high efficiency plants which operate above the critical point of water and have an average efficiency of 44%, along with lower CO₂ emissions than subcritical plants. Very modern plants with ultrasupercritical technology, which operate at temperatures above 580°C and pressures of over 25MPa, have an efficiency of over 45% (X. Tan & Seligsohn, 2010).

Currently, overcapacity results in a waste of capital and therefore remains an important issue for Chinese policy to tackle (Chasing the Dragon? China’s Coal Overcapacity Crisis and What It Means for Investors, 2016). The state of overcapacity in China also highlights continued political support for coal power (Xie, 2022). However, overcapacity also means that China’s coal power capacity expansions are not necessarily a good predictor for actual coal consumption (Bahr, 2020). A more important indicator in this regard is peaking coal consumption: in April 2021, President Xi Jinping said that China would aim to do so by 2025 (Stanway & Cadell, 2021). Still, the prohibition of coal capacity additions would be a crucial step towards a coal-phaseout. The historically lower-than-average lifespan of Chinese coal plants, as mentioned above, means that it is possible for all currently operating CFPP to reach the end of their lifetime before 2060.

Figure 7. China’s shift toward cleaner coal-fired power technology.

Technical Makeup of Chinaʼs coal-fired power capacity additions, 1980-2016 Megawatts added per year

Subcritical Supercritical

50.000

Ultra-Supercritical

40.000 30.000 20.000 10.000 0 1980

1986

1992

1998

2004

2010

2016

Source: Authorsʼ calculations are based on S&P Global Platts, “World Electric Power Plants Database, March 2017”, avaliable at https://www.platts.com/products/world-electric-power-plants-database (last accessed May 2017).

Source: (Hart et al., 2017)

Subsidies

Standards, Subsidies, Taxes and other Incentives

Lacking a common definition of what exactly constitutes a subsidy, various institutions have presented a wide array of estimates for Chinese fossil fuel subsidies (Unpacking China’s Fossil Fuel Subsidies, n.d.).

Technical Standards China has progressively tightened energy efficiency and air pollution standards of CFPPs. Of the 920 GW of total coal power capacity installed in China in 2016, 19% was ultrasupercritical, 25% supercritical and 56% is subcritical (Box 3). More precisely, as shown in Figure 7, almost all new coal plants conform to supercritical or ultrasupercritical standards, with lower CO₂ emissions per unit (Hart et al., 2017). Thanks to improved pollution control, while thermal power generation increased by a factor of 17.5 from 1979 to 2016, particulate matter emissions fell by 94%, SO2 emissions by 87% and NOx emissions fell by 85% from their peaks (Hao et al., 2015).

Subsidies to Coal Production The Global Subsidies Initiative (GSI) identified 18 subidies of coal production and quantified 11 of them at EUR 5.1 billion in 2013, excluding preferential credit support, which may be worth up to EUR 5.1 billion as well, depending on the assumptions made (Xue et al., 2015). These subsidies notably include tax breaks (at least EUR 1.7 billion), compensations for the shut-down of coal mines (EUR 909 million), investment in fixed assets from state budgets to expand and improve coal production (EUR 1.1 billion) and import and export tariff adjustments (not quantified). Subsidies to rail freight of coal (EUR 1.0 billion) were phased out in 2015.

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Subsidies to Coal Power Generation

Introduction of an Emission Trading System

In a second report, GSI identified subsidies to coal-fired power generation of at least EUR 33.2 billion in 2014. The 14 subsidies identified include subsidies to loss-making coal power plants, investments in research and infrastructure, as well as electricity policies (Denjean et al., 2016).

After years of experimenting with various regional pilot schemes, the Chinese national ETS was launched in February 2021 and went live on the Shanghai Environment and Energy exchange on July 16, 2021. It currently covers 2,225 thermal power plants, both coal- and gas-fired, which together account for around 40% of Chinese emissions (Gu et al., 2021). Further expansions into other sectors are planned, however it is already the world’s largest ETS, covering 12% of global CO₂ emissions.

In China, residential electricity tariffs are regulated and heavily subsidized (Springer et al., 2022). China introduced a dualtrack pricing system in the power sector in 1985 whereby coal miners must sell a production quota to generation companies at low price. Beyond the quota, they are allowed to sell coal at a higher price, encouraging them to increase production (H. Zhang, 2021). Dual-track pricing was initially also the norm in other sectors, but it has since been phased out. Plans to unify coal pricing as a part of wider market reforms have yet to be fully implemented (“Editorial: China Should Waste No Time in Ending Dual-Track Power Pricing,” 2021).

After various attempts to link the on-grid electricity price to the coal price starting in 2004 (J. Zhang et al., 2022), a base-priceplus-floating mechanism was introduced in 2019, where the benchmark on-grid tariff is allowed to fluctuate by up to +10% and -15% (Xu & Daly, 2021). In autumn 2021, China experienced power shortages amid high domestic coal prices. These were caused by a ‘perfect storm’ of factors, such as safety inspections following mine accidents, an anti-corruption campaign in Inner Mongolia, poor hydropower performance and a typhoon in Southeast Asia that affected shipping routes of coal import cargoes (Fishman & Zhang, 2021). Since the electricity pricing mechanism did not allow for adequate cost recovery, some generation companies subsequently reduced their power generation to prevent losses.

In September 2021, Guangdong Province announced a tariff adjustment which allowed higher coal costs to be passed on entirely to the end-users, as opposed to being absorbed by the generation company or the grid operator. In October 2021, the NDRC adjusted the base-price-plus-floating mechanism to allow price fluctuation of 20% in both directions (Xu & Daly, 2021). Additionally, while hitherto only 70% of coal-fired power was traded on the market, the notice required all coal-fired power to be sold on the market. This especially affected commercial and industrial consumers, who currently only trade 44% of their power consumption on the market yet account for over 70% of China’s total power consumption (China’s New Power Tariff Mechanism Enhances Cost Pass-Through, 2021).

Rather than imposing a cap on emissions in 2022, China is focusing on reducing emissions intensity of power generation.

Allowances are allocated for free on the basis of power plants’ actual emissions and a benchmark factor based on carbon intensity. Therefore, by reducing their carbon intensity, companies can trade surplus allowances. While coal production can therefore be expected to become more efficient and less carbon intensive, there is currently no mechanism to reduce overall emissions. Although a cap on emissions could be introduced in the future, there are currently no concrete plans to do so (Liu, 2021).

In 2021, the ETS traded a total of 178.8 million tonnes of CO₂ at a value of EUR 1.1 billion. While the opening price in July 2021 was EUR 6.54, the ETS closed the year at a price of EUR 7.52 per tonne (L. Tan, 2022). It is worth remembering that the EU-ETS got off a similarly slow start but has recently become a formidable tool of emissions reductions thanks to a successive tightening of regulations and a lowering of the emissions cap. However, as outlined above, the Chinese power sector is currently not subject to market forces and thus the success of the Chinese ETS for emissions reductions in the coal power sector will not only depend on an increase in the price of allowances and the imposition of a cap on emissions, but also a deep power market reform.

The Levelized Cost of Electricity As of 2022, the LCOE of ultrasupercritical coal in China is still below that of solar PV and onshore wind, but they are set to outcompete ultrasupercritical coal by 2026 (Figure 8). LCOE is spatially differentiated: renewables will become competitive in the wealthy demand centers on the coast as well as in central and north-eastern China first but could remain uncompetitive in regions such as Xinjiang until 2040 (Gordon, 2020).

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Due to government intervention in power pricing, however, the LCOE in China is less important for energy policy (J. Gosens, personal communication, March 11, 2022). Furthermore, the enormous environmental and social costs of coal are not included (Hwang et al., 2019).

Figure 8. Average power generation cost (LCOE) in China.

Average power generation cost (LCOE) trend in China US$/MWh Solar PV and onshore wind costs will fall to the level of coal-fired power by 2026

200 180 160 140 120 100 80 60 40 20 0 2010 Coal USC Gas USC

2015 Wind offshore Wind onshore

2020

2025

Utility PV

2030

2035

2040

Source: Wood Mackenzie

that are financed through the national government or other entities within the country, however, could be an option. For example, it has been suggested that compensation schemes for companies and workers could – along with an alteration of promotional incentives for party officials – function as a sensitive intervention point to achieve the Chinese 2060 carbon neutrality goal (van Voss & Rafaty, 2022). Measures would have to be taken in order to alleviate the perverse incentives (see Section on Pay for Closure), for example by limiting the time frame that compensation is available, as well as the companies eligible for it (van Voss & Rafaty, 2022).

One of the most significant policies to reduce coal use in China is the “dual control” policy. While it is currently only used to control energy consumption and energy intensity, President Xi Jinping has said that it will eventually be transformed into a dual control system for carbon emissions and carbon intensity (Yin, 2022). With the newly established ETS, the Chinese government has a further policy tool to phase out coal, provided that a cap on emissions is eventually imposed. The intransparency of the political process in China, however, means that such climate policy changes are hard to predict and anticipate.

Source: (Gordon, 2020)

Recommendations for Coal Phase-out The success of coal phase-out in China very much depends on the willingness of the government to lower coal consumption.

At the moment, the dominant view in China is that coal is necessary to fuel economic growth and also serve as a back up for intermittent energy from wind and solar (Cheng, 2021).

In March 2022, Xi Jinping again emphasized the importance of ensuring energy security while carrying out carbon reduction (Xie, 2022). It is evident that the blackouts in the summer and autumn of 2021 have justifiably affected thinking in this regard.

However, instead of investing in coal capacity expansion, crossprovince grid transmission needs to be improved first (“China’s Hot Summer Is Latest Test of Its Carbon-Neutrality Drive,” 2021).

China is already leading in the buildout of efficient but costly ultra-high voltage lines, which will improve the transmission of renewable energy from inland production to the demand centers on the coast (Ye & Yuan, 2021). However, technological limits and conflicts of interest between power generators, grid operators and local governments mean that many ultra-high voltage lines run only at about 60% capacity (Ye & Yuan, 2021).

Since international financing of coal phase-out in China is currently not on the table, several of the financing mechanisms introduced in this report are unapplicable. Mechanisms

57

India The Political Economy of Coal in India India’s historic reliance on coal as an affordable and domestically available fuel for economic growth has created a carbonintensive power sector, with high public investments in coal and government policies that stimulate private investments in coal.

Although the share of RE is growing in India, coal still accounts for the largest share of the electricity mix (76% in 2020), compared to 17% RE (IEA, 2021a). As of 31 January 2022, 52% of installed generation capacity is fueled by coal, compared to 39% by RE, including hydropower (Power Sector at a Glance ALL INDIA, 2022).

Though domestically available, India imports additional coal, about 215 million tonnes in 2020-21 (Indian Ministry of Coal, n.d.).

The political economy of energy in India is often discussed and analyzed along the lines of three overarching priorities that dictate the Indian energy policy environment: (1) sufficient, affordable and secure energy; (2) promotion of domestic industries and personal interests and (3) climate change and air pollution mitigation (Dubey & Lakhanpal, 2019; Grigoryev & Medzhidova, 2020; Montrone et al., 2022).

The Indian government intervenes directly in the power sector to secure long-term electricity supply. Affordable energy for all is essential for socio-economic development and as long as coal is needed to satisfy this growing energy demand, the Indian Ministry of Power will remain hesitant to let go of coal. As around 30 million people still need to be connected to electricity, and per capita electricity consumption is still only a third of the global average, this demand will only grow (Central Electricity Authority, 2022; Wetherbee et al., 2022).

The coal sector is also an essential source of revenue for the central and state governments and for SOEs. Almost 55% of CFPP are owned and operated by SOEs, 93% of coal is produced by the three largest SOEs and 60% of produced coal is transported by the SOE Indian Railways (Pai, 2021b). An estimated 3.6 million people (around 0.26% of the population) are either directly or indirectly working in the coal mining or coal power sector, and about half a million coal sector pensioners depend on the continuation of the coal industry for their pensions (Pai, 2021b).

Many of these cannot be compensated by jobs in the RE sector because many of the RE materials are imported (80% of all solar cells). Moreover, the newly created RE jobs are usually located in the South and West of the country, while most coal sector activity is in the East (Montrone et al., 2022). Therefore, to secure regional political support, state-level parties pressure the central government to continue starting projects in their constituency to keep the coal sector running.

Another major problem is the financial barrier for distribution companies to make the necessary investments to integrate RE into the national grid (Suri et al., n.d.). In exchange for political support, local politicians promise cheap and reliable electricity, often by subsidizing electricity and by allowing theft and unmetered billing (Mahadevan et al., 2020). Distribution companies have been suffering financially as a result and do not have a buffer to make the necessary grid investments to increase their share of RE. Multiple studies have concluded that the dire financial situation of distribution companies is one of the main reasons why policy incentives for RE are less effective (Jakob & Steckel, 2022; Suri et al., 2021; Tongia, 2007).

Because of coal lock-in in the energy mix, government policies such as low interest rates promoted private investments in coal and created powerful incumbents with strong relations to the government. These resist policies threatening the favorable status of coal in the private sector or initiatives that impose additional costs for coal-fired power generation. However, due to rapidly declining costs of RE (Figure 9) and the poor financials of existing and new coal power, (private) investors are shifting their investments towards RE. Therefore, it will be the public support for publicly-owned power plants which is likely to be the primary driver of continued coal investment in India (Montrone et al., 2022).

58

Figure 9. LCOE of RE cost versus new coal in India Renewables costs versus new coal in India (Levelised cost, Rs/Kwh) 6a. solar PV

12 Rs./KWh

12 Rs./KWh

10

10

8

8

6 4

6 Cost of new coal

4

2

2

0

0 2010

2012

2014

2016

2018

6b. onshore wind Without AD & Tax Benefits With AD & Tax Benefits

Commissioned 2015-2017 Cost of new coal

Capacity Weighted Average Coppetitive Bids in 2017 and 2018

Tami Maharashtra Andhra CERC Tariff Nadu Pradesh Norms

Source: Coal Transitions, based on tariff orders from CFRC and SFRCs and results of competitive bidding

Source: (Sartor, 2018)

However, this seems to be at odds with the very ambitious RE policy targets of the Indian government. India has made significant progress in achieving its NDCs under the the Paris Agreement and is likely to meet its 2030 targets. India announced the target of 500 GW non-fossil energy capacity by 2030 and achieving net-zero by 2070 (Wetherbee et al., 2022). Additionally, India co-introduced the Green Grids Initiative with the UK to establish interconnected transnational grids and to speed up the process towards affordable low-carbon technology (James et al., 2021). Since 2015, the central government has been intensifying its efforts to promote RE by increasing RE targets, enacting stronger pollution regulations for thermal power plants and encouraging RE with policy support (e.g. the Rooftop Solar Programme).

Private coal investments plummeted in the late 2010s and the government adopted a program to improve the financial situation of distribution companies. Also, despite its dependence on coal revenues and the importance of coal sector jobs, Indian Railways has been pursuing a strategy to reduce its dependence on coal.

avoid 270,000 air pollution-caused deaths, raise revenue by 1% of GDP in 2030 and reduce CO₂ emissions by 12% (Parry et al., 2017). Even though experts suggest the Clean Energy Cess was designed more to raise revenues rather than to reduce the use of coal (Montrone et al., 2022), models suggest that ramping up this existing coal tax might have higher benefits than alternatives such as an ETS, fee-bate, road fuel taxes or incentives to stimulate RE or energy efficiency (Parry et al., 2017).

India also demonstrates how a coal tax is politically achievable, despite coal’s lock-in in the political economy. India’s “Clean Energy Cess” is a tax on domestic and imported coal, and 30% of the revenues is allocated to financing clean energy technologies and projects through the National Clean Environment Fund (NCEF) (Parry et al., 2017; Sumarno & Laan, 2021). Based on models assessing the environmental, fiscal, economic and tax incidence effects of different policy options to reduce India’s fossil fuel use, this cess has proven to be the most effective tool for delivering CO₂, health and fiscal benefits in India (Parry et al., 2017). Calculations suggest that further increasing the tax

by INR 150 (EUR 1.8) per tonne of coal annually until 2030 could

The main question for India is how to phase out coal while ensuring access to affordable and reliable energy for all.

Yet, there are policies the government could implement to realize this goal. One way would be to make the power market more efficient by facilitating a more market-based incentive structure. The government recently introduced the Electricity (Amendment) Bill, which would create more competition in the distribution sector by de-licensing power distribution. If this bill is passed, the private sector can participate and compete with SOEs, potentially helping to circumvent the problem of distribution companies not being able to improve the electricity grids (Suri et al., 2021; Wetherbee et al., 2022).

However, despite environmental concerns and pollution becoming more prevalent and problematic, the general objective of sustainability has not yet been able to overcome the energy security concerns and the vested public and private interests. It is also uncertain to what extent the Coal Cess actually contributes to the actual phase-out of coal, as long as the largest stimulus for coal projects comes from the public sector itself. It is therefore clear that a more comprehensive package is necessary to phase out coal in India.

59

Even though India has an ambitious RE strategy and has already made significant progress in achieving its NDCs, the question regarding what international actors can do to help India accelerate its transition away from coal remains valid.

Looking at the conflicting overarching policy objectives, it is important to ‘pave the way’ for environmental sustainability by mitigating the negative effects on energy security and equity.

The international community could aim to mobilize funding to support coal-dependent communities, repurpose former coal plant and mine sites, and support the decommissioning and retrofitting of polluting coal-fired power plants (Busby et al., 2021). It is also suggested that to phase out coal while accounting for the different dimensions, India needs to create a feasible and long-term Just Transition plan (Pai, 2021a). International research priorities aimed at establishing such a plan focus on examining international experience on how to engage civil society in coal structural reforms, how to involve non-unionized coal workers in policy planning, review economic diversification strategies for coal-dependent regions and how SOEs have diversified, review how to reform pension funds to make them sustainable and share studies of mine site rehabilitation requirements in coaldependent states (Pai, 2021a). To leverage private sector finance, development banks play an important role to mitigate policy uncertainty and other barriers (United Nations, 2021).

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South Africa At COP26, South Africa announced the Just Energy Transition Partnership, a deal worth USD 8.5 billion (EUR 7.5 billion) which aims to decarbonize the country’s energy sector and move to a low-emission and climate resilient economy (European Commission, 2021d; Kumleben, 2021). This partnership is a promising first step to get South Africa, the 12th largest carbon emitter in the world, on track to reach its NDC to reduce its emissions by 32% in 2030 (Climate Transparency, 2021). This reduction is highly necessary as South Africa relies on its large domestic coal reserves to supply most of its energy. In 2020, South Africa’s energy mix was dominated by coal (74%), making it the most carbon-intensive economy of the G20 (Climate Transparency, 2021). On top of that, around 25% of mined coal from South Africa is exported, contributing around 1% to South Africa’s GDP (Ratshomo & Nembahe, 2019). Yet, the low-hanging fruit in terms of CO₂ reductions lies in the South African electricity market, which relies heavily upon old and inefficient CFPPs that consume 60% of all domestically produced coal and supply 87% of its electricity (Climate Transparency, 2021; Steyn et al., 2021). For that reason, the focus of this case study is on the South African power sector.

The importance of the South African coal phase-out in terms of CO₂ reduction is evident, yet it remains a contentious domestic issue due to the economic problems that South Africa has been facing in the 2010s and early 2020s. The country’s unemployment rate is over 40%, one of the highest in the world, and it is one of the world’s most unequal countries (Hanto et al., 2022). This situation has only been aggravated by harsh lockdown measures during the COVID-19 pandemic (Climate Transparency, 2021).

Further, coal-related jobs are clustered in and around the Mpumalanga Province with the vast majority of coal mines and CFPPs located there as well (Figure 10). In all of South Africa, there are between 90,000 and 170,000 people that work in coal mining, at coal power plants, or other coal-dependent sectors (Climate Transparency, 2021). Most of these jobs are located in the Mpumulanga province which makes these communities heavily dependent on coal for their livilihoods and, thus, this province should be a main focus and benificiary of the Just Transition.

LIMPOPO

Figure 10: Map of Coal Mines and CFPP in South Africa MATIMBA 3990MW MEDUPI 3597MW

MOZA MB I QU E

MPUMALANGA GAUTENG

Johannesburg NORTH WEST

ESWAT I NI

KWAZULUNATAL

FREE STATE

Bloemfontein L ESOT H O

NORTHERN CAPE

ROOIWAL 300MW

KUSILE 794MW

EASTERN CAPE

ARNOT 2352MW DUVHA 3600MW HENDRINA 2000MW

KELVIN

KOMATI 1000MW KENDAL 4116MW

600MW

KRIEL 3000MW MATLA 3600MW

WESTERN CAPE

Legend

Cape Town

Coal power plants

GROOTVLEI 1190MW

CAMDEN 1600MW

TUTUKA 3654MW

LETHABO 3709mw

MAJUBA 4110MW

Coal mines

Source: Burak Korkmaz (2022)

61

Stakeholder Overview Eskom The national utility company Eskom is arguably the most important player within the South African coal sector. This is because it is the main player within the electricy sector, where most of the country’s mined coal is consumed. Figure 11 shows a diagram of actors in the South African electricity sector.

Eskom is responsible for 90% of electricity generation, most of which largely comes from ineffiecient and old CFPPs (Table 6).

Due to the high average age of CFPPs (42 years), maintenance backlogs, and issues with newly built power plants, there often is a shortage of electricity supply on the South African grid (Geddes et al., 2020). This leads to frequent blackouts and loadshedding, which is the practice of proactively cutting of power supply to certain parts of the country when the electricity supply is running low in order to maintain grid stability.

Table 6: Age of Coal Power Plants in South Africa SOUTH AFRICA: ESKOM Age (years)

Capacity (MW)

% of Total

0 - 10

5,757

11%

10 - 20

2,165

4%

20 - 30

3,843

7%

31+

27,008

51%

Total

38,773

73%

Source: (Eskom, 2021)

Figure 11. Electricity generation, transmission and distribution by actor in South Africa.

In terms of transmission, an Eskom subsidiary is the sole Transmission System Operator (TSO) and owns all the transmission infrastructure (Geddes et al., 2020; Winkler et al., 2020). The monopoly in the transmission business effectively gives Eskom the exclusive right to buy from IPPs. Historically, Eskom has been able to abuse this power, as it for example, refused to sign PPAs which delayed the allocation of RE implemented through the South African procurement programme (Hanto et al., 2022).

However, recently the Department of Public Enterprises has outlined a roadmap which envisions four separate entities for Eskom, one holding company and three others for generation, transmission, and distribution (Department of Public Enterprises, 2019). This seperates the responsibilities of Eskom and prevents this conflict of interest, however, Eskom still plays a large role in the distribution network as it owns around 40% of distribution capacity, while the rest is owned by South African municipalities (Geddes et al., 2020).

As of early 2022, the role of Eskom is heavily discussed. Eskom’s structural issues put a significant strain on public finances and jeopardize the functioning of the entire economy. The first pressing issue in the South African power sector is Eskom’s excessive debt totaling around ZAR 400 billion (EUR 24.8 billion) in 2021 (Annex II). Eskom only avoids bankruptcy due to massive government support to the tune of ZAR 56 billion (EUR 3.5 billion) in 2021 alone (Eskom, 2021).

Second, Eskom has an old and under-maintained fleet of CFPPs. As a result, the availability factor of Eskom’s power plants has decreased from 86% in 2011 to 64% in 2021 (Eskom, 2021; Winkler et al., 2020). This resulted in 47 days of load-shedding in 2021, despite lower demand due to the COVID-19 lockdown measures (Eskom, 2021). The excessive loadshedding increases operating costs because both planned and unplanned maintenance needs to increase as a result of loadshedding.

ESKOM

MUNICIPAL GENERATORS

ESKOM GENERATION

IMPORTS ESKOM TRANSMISSION IPPs

MUNICIPALITIES

ESKOM DISTRIBUTION

CUSTOMERS

Third, the regulated electricity tariffs are not sufficient to cover Eskom’s costs. Despite a 500% increase in tariffs between 2007 and 2019 and a proposed increase of 21% in 2022 alone, electricity tariffs remain too low to cover Eskom’s operating costs8 (Geddes et al., 2020; Winning, 2021). Part of the reason is that the National Electricity Regulator of South Africa (NESRA) has historically kept tariffs low to support electricity-intensive industries, while another reason is decreasing demand due to the increase in load-shedding and price increases. At the same time, Eskom likely operates inefficiently, potentially employing 66% more staff than deemed optimal, as suggested by an analysis from the World Bank (Geddes et al., 2020). Also, a further

Source: (Ratshomo & Nembahe, 2019)

8

The inflation rate over the same period was 67.1% (South African Inflation, n.d.)

62

escalation of costs is caused by unforeseen maintenance for old CFPPs and cost overruns in ongoing construction projects.

All in all, Eskom is now deep in a utility death spiral. It suffers from decreasing demand which it tries to compensate for by increasing prices, which in turn incentivizes users to use even less electricity. This quickly becomes a vicious circle and that means that the only way for Eskom to stay afloat is through government bailouts.

The South African government envisages several measures to address these issues. The first step is the ongoing process of unbundling Eskom. It aims to improve operations, cut costs, and spread the debt burden. This is an important step for two reasons. First, based on interactions with industry players, it is generally understood that the generation branch holds the most debt. Unbundling allows the other two branches to gain financial independence, while allowing for a focused approach for debt within the generation branch. Second, it would enable competition in the electricity sector. Especially the separation of the transmission branch from the other two branches is important in this regard. This process was completed in December 2021, when the tranmission branch was transferred to a separate legal entitity named National Transmission Company South Africa SOC Limited (Rumney, 2021). This is supposed to limit Eskom’s ability to abuse its market power, especially solving issues such as the refusal to sign PPAs with IPPs.

IPPs IPPs play an increasingly important role in the South African power sector. The IPPs that were awarded a PPA in the first three rounds of the REIPPP were a mix of South African and international companies (Eberhard et al., 2014). With the expansion of the REIPPP over the coming years, IPPs are set to become more prevalent in the South African power sector.

However, there is also resistance towards IPPs from unions and other actors who are against privatization in the power sector, especially due to the complicated history of coal in South Africa (Hanto et al., 2022). During Apartheid, the white leadership and international investors profited from the coal sector. At the same time, many black communities became dependent on coal for their livelihoods. A worry among many South Africans is that the value will once again be acquired by international investors, rather than benefiting the domestic economy and native South Africans. This further underscores the importance of a Just Transition.

9

Citizens The main concerns of South African citizens are electricity stability (i.e., minimization of load-shedding) and low electricity prices. In post-Apartheid South Africa, electricity access has risen dramatically from 35% access to electricity in 1990 to 85% in 2019 (Bohlmann & Inglesi-Lotz, 2018; The World Bank, n.d.). Yet, many South Africans still live in energy poverty. Despite the Free Basic Electricity (FBE) programme implemented by the government in 2003, which provides poor households with 50 kWh of free electricity a month, 43% of South Africans were energy poor in 2012 (Bohlmann & Inglesi-Lotz, 2018). Hence, three-quarters of South Africans said that the government’s top priority should be to keep electricity prices low, while a further priority should be to minimize load-shedding and power cuts (Department of Energy, 2013)9. Since then, electricity prices and load-shedding have increased significantly, so it can be assumed that these issues remain important for South African citizens.

Government The national government is led by the African National Congress (ANC) party, that holds an absolute majority with 58% of the seats in the National Assembly since 2019. The ANC has been riddled with corruption scandals ever since the end of Apartheid in 1990. South Africa is often characterized as a country suffering from state capture, a situation in which the state’s institutions are reshaped to serve individual interests (Fredericks & de Jager, 2021; Madonsela, 2018). Eskom was also reportedly involved in state capture in the last decade with unlawful payments to companies linked to South African politicians and their friends and families (Fredericks & de Jager, 2021; Madonsela, 2018). Although the current administration has spoken out against corruption and supported a large-scale investigation into these issues, Eskom and other parts of the economy remain at risk for state capture (SA News, 2022). This risks distracting attention and resources away from the coal phase-out.

One of the most important initiative that shows the government’s intent to tackle the coal phase-out and the Just Transition is the Presidential Climate Change Coordinating Commission (PCCCC). The PCCCC is tasked with co-ordinating a Just Transition across all stakeholders involved (Halsey et al., 2019). It also recently updated its climate mitigation commitments in South Africa’s NDC. However, it largely lacks the financial means to invest in the Just Transition and the coalphase out due to large public debts, partially a result of Eskom’s bailouts and a myriad of other economic issues to resolve.

Note that this data was collected in 2011 and 2012 and may be outdated, but it was the most recent data available in early 2022.

63

Ministries

Civil society groups

The energy sector is regulated by several different government ministries more often called departments within South Africa.

The Department of Mineral Resources and Energy (DMRE) is responsible for mining and electricity regulation as well as the allocation of new generation capacity (Hanto et al., 2022).

The Department of Public Enterprises is responsible for the operation of SOEs, such as Eskom. Especially important for the functioning of Eskom is the National Electricity Regulator of South Africa (NERSA), which determines the level of electricity tariffs. NERSA is tasked with a difficult balancing act as it tries to keep electricity prices low but tariffs high enough to cover Eskom’s (escalating) costs, often putting more importance on the former rather than the latter. Other ministries that regulate the energy and coal sectors are the Department of Trade, Industry, and Competition (DTIC), which administers industrial policy and the Department of Forestry, Fisheries and the Environment (DFFE) responsible for environmental conservation and climate change policy (Hanto et al., 2022).

Civil society groups have also started playing a bigger role in ensuring that South Africa reduces its carbon emissions and achieves a Just Transition. There are many organizations that oppose coal for environmental and health reasons, especially in the coal-dependent region of Mpumalanga (C. Renaud, personal communication, February 23, 2022).

Municipalities Municipalities play an important role in the South African electricity sector as they own 60% of the distribution networks (Geddes et al., 2020). The revenues generated from these distribution networks are used to provide Free Basic Electricity for their citizens. However, due to the increasing uncertainty about energy supply, citizens have been installing solar PV panels on their properties without approval by the grid operators, which means they don’t generate revenues for municipalities (Geddes et al., 2020). Illegal connections and missed payments decrease municipal electricity revenues even further, which makes it harder for municipalities to provide FBE. Further, municipalities are exploring the ways in which they can circumvent Eskom’s dominance in the electricity market.

Due to the high frequency of loadshedding, some municipalites want to connect RE capacity provided by IPPs directly to their distribution networks. The national government signaled that municipalites are now allowed to connect to IPPs rather than being forced to rely on Eskom’s generation and transmission division for their electricity. Cape Town is currently putting this opportunity to the test and jumping through many bureaucratic hoops to get there (Cotterill, 2022). If successful, this could prove to significantly increase grid stability in the city, as well as open up the opportunity for other municipalites to follow suit.

10

Labour Unions One of the most important civil society actors are labour unions, collectively represented by the Congress of South African Trade Unions (COSATU). This congress consists of 21 different labour unions representing around two million members. They have an intimate relationship with the ANC and the South African Communist Party as they have been in a ‘Tripartite Alliance’ since 1994 (Hanto et al., 2022). The number of workers in the coal sector that are represented by the labour unions is hard to determine, but it most likely includes the number of people working in coal mines, CFPPs and other coal-related sectors which ranges somewhere between 90,000 and 170,00010 (Chamber of Mines of South Africa, 2018; Climate Transparency, 2021).

Labour unions have played an important role in the transition away from coal in South Africa. Contrary to some views, labour representatives have in many instances presented a supportive role for the low-carbon transition, not just resistance, but on conditions that workers are placed at the front and center of the transition. Labour unions have repeatedly stressed the importance of demonstrating that new jobs will be created, and new skills training will be provided for impacted workers; in fact, this cannot just be ‘spoken about’ - it needs to be demonstrated (C. Renaud, personal communication, February 23, 2022). For this reason, labour unions are often against the privatization and unbundling of Eskom, as they argue that it will lead to mass layoffs (Geddes et al., 2020).

Around 0.5 and 1% of the total workforce (Hanto et al., 2022) 64

South African Power Sector As discussed before, the South African power sector is heavily reliant on domestic coal mining and CFPP for its power production across all sectors of the economy. The coal mining sector is dominated by five companies11 and is projected to have reserves for another 50 years. Around 21% of produced coal is exported and the remainder is used domestically in the following sectors (Department of Mineral Resources and Energy, n.d.): • • • •

Electricity generation (62%) Petrochemical industry run by Sasol (23%)12 General industry (12%) Sold to merchants to sell locally or for export (4%)

Historically, electricity has been generated using CFPPs, while only recently there has been the opportunity for RE to be installed through IPPs. In 2020, around 87% of all electricity that was generated came from CFPPs, while only 7% came from RE, including hydropower, biomass, solar PV and wind (IEA, n.d.). Yet, this number has risen from 2% in 2010, due to the introduction of the Renewable Energy Independent Power Producer Procurement Programme (REIPPPP). This opened the opportunity for IPPs to join in a competitive bidding programme to supply RE to the grid. The government supported IPPs with a sovereign guarantee in case Eskom, as the single buyer of the power, defaulted on their payment (C. Renaud, personal communication, February 23, 2022). The REIPPPP has been relatively successful, allocating more than 6.4 GW of capacity to the national grid, as well as providing around 40,000 jobs between 2011 and 2019 (Halsey et al., 2019; Hanto et al., 2022).

The Grid The South African electric grid has a number of issues that need to be tackled during its energy transition. Despite the increase in RE capacity through the REIPPPP, electricity generation has not been able to meet demand, resulting in loadshedding and blackouts.

In 2021, Eskom reported that on 47 days it had to implement loadshedding to maintain grid stability (Eskom, 2021). As discussed before, this is mainly due to old and under-maintained CFPPs and operational problems with new CFPPs. The transmission and distribution networks face similar challenges.

Due to underinvestments, infrastructure is aging and needs to be upgraded. The stability of the grid is further challenged by theft, vandalism, and illegal connections (Eskom, 2021).

11 12

Hence, necessary improvements to the grid are multifold.

Generation capacity needs to be increased, especially as Eskom is aready planning to decommission around 10 GW of power in the next decade while demand is projected to increase (Eskom, 2021).

Ideally, this would be replaced with RE such as wind or solar PV. To accommodate increased RE capacity, the transmission grid also needs to be modernized and upgraded. In addition, the distribution network needs to be expanded, especially as 15% of the population is not yet connected to the grid (The World Bank, n.d.). Furthermore, some efforts should focus on mini-grids to provide remote communities with electricity.

National Energy Policy Generally, the South African political economy can be characterized as a Minerals-Energy Complex (MEC) which means that minerals and energy have a disproportionate influence on South African politics relative to the contribution to its economy (Winkler et al., 2020). Historically, coal became locked-in before and during the Apartheid era when the government’s priorities lay with generating cheap electricity for industry and mining, resulting in exploitation of black labour and disproportionately benefiting white industry owners (Halsey et al., 2019). Throughout the 1970s, there were massive investments in coal mines, CFPPs, coal-to-fuel plants and an increase in coal exports (Winkler et al., 2020). When Apartheid ended in 1994, the Minerals-Energy Complex remained dominant. Industrial policy, funding and incentives, and the liberalization of the economy consolidated the dominance of minerals and energy sectors (Winkler et al., 2020). Although the 2010s saw some increase in the usage of RE and the introduction of some climate policies, the state still heavily supports the coal industry in the early 2020s. The power sector is exemplary of the Minerals-Energy Complex in South Africa, with the state having strong ties with the national utility company, Eskom.

Despite this, the South African energy policy landscape also has a relatively long tradition of green energy policy. However, it is also quite fragmented and incomplete in terms of policy implementation. The earliest work on energy policy and RE was published in two White Papers in 1998 and 2003. Together, these papers lay out the way in which supply and demand of energy would be met in the country (Department of Public Enterprises, 2019). Another policy document published in 2003, the Integrated Energy Plan (IEP), outlined the general energy plan for the country and was updated in 2016. This plan was further developed for the electricity sector and published in 2010 as the Integrated Resource Plan (IRP) outlining the planning, quantitites, and sources of electricity generation between 2010 and 2030 (Hanto et al., 2022).

These companies are: Ingwe Collieries Limited (a BHP Billiton subsidiary); Anglo Coal; Sasol; Eyesizwe; and Kumba Resources Limited Sasol is the state-owned coal-to-liquids producer.

65

A further development was the National Climate Change Response White Paper that was published in 2011 and formed the basis for the climate mitigation targets that South Africa set out in its NDCs in the Copenhagen Accord of 2009 (Halsey et al., 2019)13

billion [EUR 18.6 billion]), 16 GW of coal power capacity would be at risk of being shut down (Sheree, 2021). It is unclear whether Eskom will be able to comply with the standard in 2022 and what the consequences would be for non-compliance.

Subsidies In 2012, the National Development Plan (NDP) was implemented to reduce poverty and inequality in the country and one of the pillars mentioned specifically is the Just Transition in the energy sector (Halsey et al., 2019). In 2019, the updated version of the IRP was introduced, which runs until 2030. In the IRP (2019), a concrete strategy for phasing out coal and introducing more RE, storage and gas to the electricity sector is laid out (plans are summarized in Table 7).

South Africa is also expected to pass the Climate Change Bill in 2022, which is supposed to further develop the framework for decarbonizing the economy through a Just Transition (Parliament of the Republic of South Africa, 2022).

Table 7: Electricity Sector in 2030 SA, according to IRP 201914

Taxes

Coal

PV

Wind

Storage

Capacity in 2018 (MW)

37,194

1,474

1,980

2,912

Decommissioned (MW)

11,417

n.a.

n.a.

n.a.

Capacity increase (MW)

7,232

6,814

15,762

2,088

Total installed capacity (MW)

33,364

8,288

17,742

5,000

58.8

6.3

17.8

1.2

% Annual energy contribution (MWh)

Source: (Department of Mineral Resources and Energy, 2019)

Standards, Subsidies, Taxes and other Incentives Standards The most important standard regarding the coal sector in South Africa is the Minimum Emission Standard implemented in 2010. It regulates the accepted levels of particulates, sulfur dioxide, and nitrogen oxide emitted within South Africa. The law went into effect in 2015 but large polluters, including Eskom and Sasol, received waivers until 2020. However, a further postponment request submitted by Eskom in 2021 was denied.

This led Eskom to warn that due to the high costs of compliance with this standard, (Eskom estimated compliance at ZAR 300

13 14

The South African government strongly supports coal in multiple ways. Coal mining is supported through government funding for water transportation projects serving coal mines.

These subsidies amounted to approximately ZAR 804 million (EUR 49.8 million) in 2020 alone (OECD, n.d.). In terms of subsidies for coal-fired power production, the South African government gives substantial support to Eskom, otherwise risking that Eskom will default on paying its debts. Support to Eskom amounts to roughly ZAR 50 billion (EUR 3.1 billion) per year, reaching a level of ZAR 56 billion (EUR 3.5 billion) in 2021 (Eskom, 2021). Coal consumption is also supported through the FBE. In 2020, ZAR 11.65 billion (EUR 720 million) was spent on electricity generated by CFPPs (OECD, n.d.).

In 2019, the South African government introduced a carbon tax.

The first phase of this carbon tax was set at ZAR 120 (EUR 6.6)/ tCO₂e and increased with 2% plus inflation until 2022 (South African Revenue Service, 2021). From 2022 onwards, the tax will only increase in accordance with inflation. The effectiveness of this tax is limited because of tax-free emissions allowances ranging from 60 - 95%. As a result, the net rate of taxation ranges from ZAR 6-48 (EUR 0.37 – 2.97) per tonne of carbon. Most notably, Eskom has been exempted from the carbon tax up until 2022, although the government has rejected the request to continue this exemption in 2022, which means Eskom is supposed to pay the carbon tax this year (Dludla, 2021).

South Africa receives a significant portion of its tax revenues from fossil fuels. The main source is from taxes levied on transport fuels. The total amount of fossil fuel taxes amounts to 7% of total revenues, where transport fuel taxes are responsible for 83% of this number (Bridle et al., 2022). The coal sector is a relatively small contributor to the national budget. One of the ways it does contribute is through The Environmental Levy on Electricity Generation, which contributes roughly 0.7% to government revenues, of which 95% is coal-related (Bridle et al., 2022).

Through the Corporate Income Tax and the Mineral and Petroleum Resources Royalties, a further 0.25% of government revenues are linked to fossil fuels, mostly concerning coal although the exact percentage remains unclear (Bridle et al., 2022).

Interesting to note is that South Africa is the only country that included the concept of Just Transition in its NDC. Excluding Nuclear, Hydro, CSP, Gas/Diesel, and others

66

The Levelized Cost of Electricity As of March 2022, solar PV and wind energy already outcompete coal as the cheapest forms of electricity in South Africa. In the fifth bidding window of the REIPPPP, the price of new renewables was lower than running existing CFPPs. The average price of new renewables was EUR 29.28/MWh while Eskom’s coal purchases amount to EUR 26.06/MWh, which becomes higher than RE when factoring in capital, operational, and maintenance costs (Planting, 2021). This is underpinned by additional research (illustrated in Figure 12) which projects that the LCOE in 2025 is USD 28.2 (EUR 24.9)/MWh and USD 34.60 (EUR 35.5)/MWh for solar PV and wind, respectively. This is considerably lower than coal at USD 45.53 (EUR 40.2)/MWh (Whitaker, personal communication, February 23, 2022).

However, some barriers remain to increasing RE installations in South Africa, including policy and regulatory uncertainty after several years of the REIPPPP process stalling which had a negative impact on investor confidence (C. Renaud, personal communication, February 23, 2022). Second, the fiscal space for South Africa’s government to provide sovereign guarantees is becoming increasingly constrained due to a few other fiscal obligations and priorities emanating from the COVID-19 pandemic. There is currently ongoing work aimed at exploring alternative mechanisms that might be able to replace the need for sovereign guarantees and which will still enable projects to become bankable. Recent shifts in the regulatory regime to enable projects to sell to multiple customers may reduce offtake risk for projects and eventually remove the need for guarantees (C. Renaud, personal communication, February 23, 2022). Third, the bureaucratic barriers to installing RE as a private individual or business are still high, but this is changing.

Until recently, individuals or businesses had to apply for regulatory approval to install RE, which was in most cases very difficult to obtain due to lengthy processes and lack of capacity at the regulatory agency (C. Renaud, personal communication, February 23, 2022). As of early 2022, the regulations have changed and it has become easier to install RE as energy consumers, with a number of large businesses announcing the development of renewable energy projects.

15

Figure 12: The modeled LCOE of energy sources in South Africa by 2025.15 Levelised cost of energy* in 2025 (Real 2020 $/MWH) Utility PV Wind Coal CCGT Nuclear CSP

Fuel opex

31

Non-fuel opex Levelised capex

38 50 63 89

107

OCGT

141

Source: (Whitaker, personal communication, February 23, 2022)

Financing As already outlined in the IRP (2019), the South African government plans to decrease its dependency on coal between now and 2030. However, to achieve a coal phase-out it should not only go through with the planned decommissioning of approximately 11 GW, but it should increase its decommissioning ambitions and halt plans to increase coal capacity by 7 GW (Department of Mineral Resources and Energy, 2019) The cost estimate ranges for a coal phase-out and/or Just Transition are quite broad. Eskom itself has presented figures ranging from EUR 9.1 billion to EUR 31.9 billion over the next 15 years to decommission 22G W of coal power and replace it with RE as well as building up the necessary transmission infrastructure (Cotterill & Khan, 2021; Creamer, 2021). A study

by Meridian Economics presented several options to speed-up the coal-phase out in South Africa: the Paris-aligned pathway achieves coal phase-out by 2040 and they model four options for reaching these goals which model costs between EUR 6.97 billion and EUR 20 billion (Steyn et al., 2021).

Assumptions: Gas price = USD 8/mmbtu, coal price = USD 2/mmbtu, WACC = 7% (pre-tax, real). Load factors – CCGT 70%; Coal 80%; OCGT 10%; Wind 40%; Solar PV 26%.

67

An important step in supplying these funds is made through the JETP, introduced in chapter 1, as a financial partnership to support South Africa through Just Transition interventions, power sector decarbonsiation, and economic diversification into future energy sectors, including e-mobility and green hydrogen. A lot is unknown about how and where the finance will flow and it is anticipated that the details will be worked out and determined during the years 2022/2023 (S. Keen, personal communication, February 28, 2022).

Another problematic issue is related to Eskom’s significant levels of debt (estimated at EUR 24 billion). It remains unclear in what ways this will be tackled as no stakeholders involved have proposed a way forward. The JETP was conceived to address decarbonisation; it would not directly address Eskom’s debt nor the government’s plan for unbundling Eskom (S. Keen, personal communication, February 28, 2022). Further, it seems unlikely that the South African government would have the fiscal capacity to take on additional debt, but of course this will depend on the terms of the forthcoming JETP (S. Keen, personal communication, February 28, 2022).

68

ANNEX II – COAL PLANT CLOSURE AND BALANCE SHEET ANALYSIS

2018 TOTAL ASSETS TOTAL LIABILITIES Total equity REVENUES Sales of Electricity Government Subsidy OPERATING EXPENSES OPERATING PROFIT (LOSS) INCOME (LOSS) FOR THE YEAR Income (LOSS) FOR THE YEAR / without Subsidy

PT Perusahaan Listrik Negara (Persero) rp billion EUR billion 2019 2020 2018 2019

2020

2018 736955 569718 167237

1,492,488 565,074 927,414

1,585,055 655,675 929,380

1,589,060 649,247 939,813

90 34 56

102 42 60

92 38 54

344,173 263,478 48,102 308,189 35,984 11,576

359,606 276,062 51,712 315,441 44,165 4,322

345,416 274,898 47,988 301,008 44,407 5,993

21 16 3 19 2 0.7

23 18 3 20 3 0.3

20 16 3 17 3 0.3

-2.2

-3.0

-2.4

Equity ratio (%) Debt rate (%) Return on equity (%) Turnover profitability (%)

62.1 0.6 1.2 3.4

58.6 0.7 0.5 1.2

59.1 0.7 0.6 1.7

Return on equity adjusted (%) Turnover profitability adjusted(%)

-3.9 -10.6

-5.1 -13.2

-4.5 -12.2

100 % government

Eskom Holdings SOC Ltd (Eskom) r million EUR billion / (dt M rd) 2019 2020 2018 2019 755704 605726 149978

822939 637076 185863

179892

199468

-20930

45 35 10

-20502

22.7 3.4 0.0

2020

48 39 10

46 35 10

3,507,790 1,384,189 2,123,601

3,720,980 1,552,513 2,168,008

3,998,862 1,826,851 2,172,011

11

11

1,454,436

1,351,658

1,478,614

-1.33

-1.14

1,042,145 412,291 118,717

1,043,672 307,986 163,531

1,311,571 167,043 47,374

19.8 4.0 -14.0 -11.6

22.6 3.4 -11.0 -10.3

Strategic 100% state-owned electricity utility, strongly supported by the government Government has committed R112 billion support over the next three years with R56 billion for 2021, R33 billion for 2022 and R23 billion for 2023.

Owner

2019

ENGIE ENERGIA CHILE S.A. Y FILIALES kUSD EUR billion 2020 2021 2019 2020 3.1 1.2 1.9 1.3 0.9 0.4 0.1

3.0 1.3 1.8 1.1 0.8 0.3 0.1

3.5 1.6 1.9 1.3 1.2 0.1 0.0

60.5 0.7 5.6 8.2

58.3 0.7 7.5 12.1

54.3 0.8 2.2 3.2

ENGIE is the controlling shareholder of our subsidiary ENGIE Energía Chile S.A. with 59.99% of the capital; the remaining percentage is traded on the Santiago Stock Exchange and distributed among Pension Funds, Institutional Investors and others.

Find here all our financial and legal information.

Rating S&P Moody FitchRatings Links to documents Exchange rate as of 31.12.2021 Rupia : 1 EUR Rand : 1EUR USD : 1EUR

BBB

The downgrade of the sovereign credit rating by Moody’s has placed the country at sub-investment grade level across all three internationally recognised credit rating agencies

Baa2

BBB Ikhtisar-Keuangan-082021.pdf (pln.co.id)

16,649

15,583

0005_Eskom-AFS-2020.pdf

ESTADOS-FINANCIEROS-31.12.21.pdf (engie-energia.cl) Inversionistas - Engie Energia (engie-energia.cl)

17,252 16.5

15.7

2021

18.0 1.11986

1.22824

1.1324

69

Inter-American Development Bank's Decarbonization Instrument

t reduction

Subsidy

500,000 tpa

15,000,000 USD loan with subsidy 3% Interst rate differntiate to market rate 450,000 USD/a grant 0.90 USD / tonne carbon annual reduction 0.73 EUR / tonne carbon annual reduction

Coal Capacity

268 MW 1679.10 USD/MW

German Coal Exit Calculations as calculated in Nacke (2020) the cost estimates include compensation paid to lignite companies, closure premiums to hard coal companies and additional payments for structural development in coal-dependent regions CO2 emissions avoided in the case of a 2035 phaseout (tonnes) avoided in 2038 phaseout (tonnes)

1524600000 1301300000

USD Euro lower cost boundary 47531100000 38698544258 upper cost boundary 80100500000 65215674461 only compensation + closure premiums 6350000000 Conversion rate as of 31.12.2020 €/t reduction lower boundary €/t reduction upper boundary €/t reduction only compensation + closure premium

1 USD = 0.81417€ 25.38 42.78 4.17

70

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Schockling, A., Miller, J., van Dedem, F., Tetteroo, M., Simon, L., Rusnok, D., and Tjallema, P. Options and Challenges to Financing the Coal Transition in SPIPA Countries – A research study by Climate & Company. 04/2022.

Vertreten durch: Ingmar Juergens David Rusnok

Dr. Herrmann and Mustafa Yashi supported the team with data analysis.

This publication and further information on our Just Coal Transition project are available online on our dedicated webpage.

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Verantwortlich für den Inhalt nach § 55 Abs. 2 RStV Ingmar Juergens & David Rusnok Ahornallee 2 12623 Berlin

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COMMISSIONED BY Deutsche Gesellschaft für Internationale Zusammenarbeit (GIZ) GmbH and the European Commission

AUTHORS Amanda Schockling, Juliane Miller, Floris van Dedem, Max Tetteroo, Louise Simon, David Rusnok and Pjotr Tjallema Design & infographics: Burak Korkmaz, burakkorkmaz.de Proofreading: Vera von Lieres Title picture: © Burak Korkmaz Version: 1.0, April 2022

ACKNOWLEDGEMENTS The authors would like to express their sincere gratitude to Jorrit Gosens from Australian National University, Oliver Sartor from Agora Energiewende, Franziska Holz from DIW-Berlin, Pao-Yu Oei and Paola Andrea Yanguas Parra from TU-Berlin and Budhi Setiawan from Sriwijaya University, Indonesia for their valuable comments and insightful contributions.

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This publication was produced with the financial support of the European Union’s Partnership Instrument and the German Federal Ministry for the Environment, Nature Conservation, and Nuclear Safety (BMU) in the context of the International Climate Initiative (IKI). The contents of this publication are the sole responsibility of Climate & Company and do not necessarily reflect the views of the funders.

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