Scaling up finance for the just transition beyond coal

By Sabrina Muller, Nick Robins, Grantham Research Institute, London School of Economics

The finance sector has an important role to play in ensuring support for workers and communities in the coal-to-clean transition. Leading institutions are taking first steps to integrate the just transition in their policies and practices. Action now needs to be scaled up, focusing on local needs and delivering tangible social impact, say Sabrina Muller and Nick Robins.

The finance sector has an important role to play in ensuring support for workers and communities in the coal-to-clean transition.
The finance sector has an important role to play in ensuring support for workers and communities in the coal-to-clean transition.

This insight article is based on the authors' policy brief "Financing the just transition beyond coal" available below. The brief will be presented at "Just Zero – a Virtual Conference on Financing the Just Transition" on 27 October. 

The growing importance of a just transition beyond coal

The just transition is a critical enabling factor for the shift away from coal. COP26 is the first climate summit taking place after the outbreak of COVID-19, and the pandemic has underscored the need for a green recovery that tackles deepening inequalities and vulnerabilities in the global economy. The Just Transition Declaration, to be launched at COP26 by governments, is expected to renew the political commitment to mitigating social risks and realising social opportunities in the net-zero transition.

As the transition accelerates, increasing attention is being placed on the implications for jobs and livelihoods. Analysis suggests that a net-zero economy will have more jobs than one based on fossil fuels. But the location of job losses and employment gains will be uneven. Furthermore, there is the need to make sure that new green jobs are also high-quality jobs with decent working conditions.  The just transition imperative extends beyond direct impacts to employment, in particular for communities who rely on high-carbon activities, such as fossil-fuel-dependent regions. The Paris Agreement is clear that governments hold the primary responsibility for delivering a just transition, with business, trade unions and civil society playing a part too. The financial sector is also pivotal, notably in the way it allocates capital for the transition.

How finance is taking practical action

Financial institutions are starting to recognise their responsibility and their role in delivering a just transition. There are clear strategic reasons for the financial institutions to integrate environmental and social dimensions in their climate strategies, including respecting social standards, supporting sustainable development and contributing to positive social impact. Minimising systemic risk is another important reason, especially as an unjust transition would likely lead to a delayed or more costly shift to net-zero, and would exacerbate poverty, posing financial risks.

Examples of finance sector initiatives include the Powering Past Coal Alliance (PPCA) Finance Taskforce, launched in June 2020, with members of government and financial institutions working together to halt new investments in coal-fired power, phase out existing coal capacity and enhance investments in clean energy. The PPCA’s Just Transition Taskforce, meanwhile, aims to ensure that coal exits are completed in ways that are socially equitable.

Upcoming company assessments, such as by the investor-led Climate Action 100+ and the World Benchmarking Alliance, can help financial institutions integrate the just transition into due diligence processes. Engagement with portfolio companies and clients has so far led to the most tangible results in terms of corporate action, for example encouraging the UK energy utility SSE to publish a dedicated Just Transition Plan. Incorporating the just transition into capital allocation is also gaining traction, with Amundi’s Just Transition for Climate fund an early example.      

Mainstreaming finance sector action

Action now needs to be scaled up to achieve meaningful, far-reaching impacts. Current finance sector initiatives for a just transition away from coal are still new, small-scale and incomplete. The just transition now needs be adopted by every financial institution in every region and for every asset class.

To make this a reality, it will be essential that financial institutions make the just transition a key part of their net-zero plans. A clear set of just transition expectations is needed to drive corporate practice: the Grantham Research Institute at LSE has published a shared framework building on existing social standards and emerging practice. Adopting a place-based angle will also be important, ensuring that social dialogue with coal workers and engagement with coal-dependent communities become integral to corporate decision-making. Emerging and developing economies will need to be a particular focal point for a just transition, given large dependencies on coal, significant investment needs and often weak social safeguards.

Looking ahead, the just transition is set to become a core element of financial sector climate action, accelerating the shift to net-zero while generating positive social impacts.

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Action to end new coal construction builds ahead of COP26

By Powering Past Coal Alliance Secretariat

New analysis shows that many countries could readily commit to “no new coal” ahead of UN climate talks COP26 in Glasgow this November, bringing the end of new coal construction into sight. PPCA members have set an example for the rest of the world by committing to end the construction of new unabated coal plants and to phase out existing capacity.

Governments are ending support for new coal projects in response to concerns over the climate crisis and competition from renewables.
Governments are ending support for new coal projects in response to concerns over the climate crisis and competition from renewables.

Ending new coal construction vital to 1.5oC goal

Ending coal power generation is central to keeping the 1.5oC goal within reach and 2021 is a pivotal year to making this a reality. Meeting the climate goals depends especially on the world’s resolve to end construction of new unabated coal plants. According to the IEA, to achieve the global transition to net zero emissions by 2050, action to tackle coal emissions must be rapidly stepped up and, as an immediate first step, the development of new unabated coal-fired power plants must stop - already this year.

Pressure grows for commitments to ‘no new coal’

The Powering Past Coal Alliance has been leading calls for an end to emissions from coal power, starting with stopping new coal plant development. Since the launch of the PPCA in 2017, every new member commits to no new unabated coal plants, alongside ending financing of coal power generation and delivering a coal phase out in line with Paris Agreement timeframes. Through diplomatic outreach and knowledge sharing, the Alliance also encourages and supports other governments who wish to begin a process toward a phase out.

In the past two years, United Nations Secretary-General António Guterres added new momentum to global efforts to stop construction of new coal plants. Speaking at the PPCA Summit in March this year, he urged all governments, private companies and local authorities to cancel all global coal projects in the pipeline, as a first step toward phasing out coal by 2030 in the OECD, and by 2040 in the rest of the world. In June, G7 members also recognised that "continued global investment in unabated coal power generation is incompatible with keeping 1.5°C within reach." Most recently, countries most vulnerable to the adverse impacts of climate change in the Pacific region have underlined that “further development of coal as the most polluting conventional energy source is totally inconsistent with the Paris Agreement’s goals and could render 1.5oC impossible”.

New coal projects in decline

Global trends for new coal development are moving in the right direction. According to new analysis released by PPCA partner E3G last week, there has been a historical shift in investment away from new coal plants since the Paris Agreement was signed in 2015. Proposed new coal power capacity globally has plunged by over three-quarters in the last five years, with 1,175 gigawatts of new coal projects cancelled.

According to the think tank, 44 countries have already committed to no new coal. This includes all 41 national government members of the PPCA, who made this commitment as a condition of membership, as well as Chile, Sri Lanka and Malaysia. A further 40 countries are now in a position to do the same, following the cancellation of previously proposed power plants. Only 37 countries (less than one in five globally) still plan to build new coal power plants, 16 of which have only one project left.

Governments are ending support for new coal projects in response to concerns over the climate crisis and competition from renewables. Coal plants are increasingly financially unviable and cease to attract funding and insurance, as new renewables are cheaper than new coal in all major markets around the world. This year, G7 countries, South Korea, and the Asian Development Bank have pledged to stop international finance for new unabated coal projects. The number of private financial institutions signing up to the PPCA to work together to cease new investments in coal-fired power has also been growing fast.

PPCA members leading the way

PPCA members have opened a pathway for others to take the first steps towards coal phase-out by acting on no new coal. Many, like Austria or Belgium have not considered new coal plants since 2015. The UK committed to a policy of ‘no new coal without CCS’ in 2009, which effectively put an end to ~15GW of proposed new coal power plants. The Netherlands, Germany and Greece turned their backs on recently constructed or planned new coal power plants. Most recently in 2021, North Macedonia and Montenegro confirmed that their aging coal power plants would not be replaced by new coal power, setting an example to neighbours in the Balkans.

Most PPCA members are now focused on accelerating retirement of existing coal power generation, with 56% of capacity either closed already since 2010 or scheduled to close by 2030. They are also working with other countries who need support to scale up renewables in place of coal plants. They are already seeing environmental, economic and human health benefits of the clean energy transition. Their fast progress gives reassurance to others that they can both stop building new coal and start a rapid transition towards clean energy to lay the foundations for a sustainable energy system.

All countries are now faced with a significant opportunity to end new coal construction at COP26, helping to deliver on the summit’s key goal to “consign coal power to history” set by COP President Designate Alok Sharma. They can put their full weight behind this effort by formally committing to ‘no new coal’ at the earliest opportunity ahead of the summit, starting with the UN General Assembly and the High-level Dialogue on Energy this week.

South Korea must take opportunity to end coal power and accelerate renewables build-out by 2028

By at Carbon Tracker Initiative

Ending the use of coal for power generation in South Korea by 2028 is not only possible but also the most economical option in the country’s pursuit of carbon neutrality by 2050, according to a report published last month by PPCA partner the Carbon Tracker Initiative, as well as South Korea-based Chungnam National University and NGO Solutions for Our Climate.

Setting an early coal phase-out date is the critical first step to reach net zero emissions.
Setting an early coal phase-out date is the critical first step to reach net zero emissions.

A complete phase-out of coal power by 2028 could result in savings of up to US$5.5 billion for the South Korean power system compared with current government plans, allowing for reductions in electricity costs for domestic consumers.

The country’s leaders have an opportunity to set a clear and ambitious phase-out deadline for coal power at the upcoming P4G Seoul Summit later this month. They should take the chance to position the power system on a trajectory for net zero by 2050 by aiming to end the use of the fuel as soon as possible.

Time for net zero alignment

Delivering net zero by mid-century will require an urgent realignment of South Korea’s power system, with greater renewables penetration needed earlier than currently planned.

The carbon neutrality pledge was made by the South Korean government late last year. Soon after, the country’s National Council on Climate & Air Quality advised Korean ministers to consider a 2040 latest end date for coal-fired power generation to achieve the aim.

But a cost-optimized analysis laid out in the End in Sight report shows that South Korea can phase out its entire coal-fired plant fleet before the end of the current decade.

Plans to reach 54GW of installed renewable generation capacity by 2031, laid out in the country’s 9th Basic Plan for Electricity Supply and Demand from December 2020, can be brought forward to 2028 when applying maximum growth rates in solar and wind power from recent years (32% and 27% year-over-year, respectively). 40GW and 14GW for solar and onshore wind capacity are feasible by 2028, against 27GW and 13GW put forward in the Basic Plan.

According to the analysis, if greater renewable energy production and storage coincides with the more effective carbon pricing regime currently under discussion, coal plant usage and profitability in South Korea soon begin to rapidly decline.

Coal units’ profit margins have already been squeezed in recent years. This is because the settlements received by electricity generators from the state-owned Korea Electric Power Corporation are limited to a level below the current spot power price, which has declined over the past decade.

And if coal plants’ operation hours dip owing to the increased availability of cheaper renewable energy, coal plant operators will struggle to recover costs. This will facilitate an earlier phase-out of existing coal power plants. It will also make the construction of new plants commercially unviable beyond 2030.

Earlier coal end could produce consumer savings

The accelerated deployment of renewables, with a marginal operating cost of close to zero, and an earlier coal phase-out are projected to reduce operating costs of the whole system by US$4 billion annually.

These savings will pull the estimated costs of the system through to 2050 down to a net present value of US$3.4 billion. When compared with the US$8.9 billion net costs incurred if following the 9th Basic Plan, earlier coal phase-out brings an economic benefit of as much as US$5.5 billion.

This represents a welcome opportunity for the South Korean government to use these savings to reduce costs for ratepayers.

P4G Seoul Summit

The P4G Summit will be held in Seoul over 30-31 May 2021, bringing together heads of states, CEOs and civil society leaders to reignite the discussion over the urgent climate action needed globally, ahead of COP26 in November.

As the host nation, South Korea has a clear opportunity to set the tone for discussions by following up on its climate neutrality pledge and committing to an ambitious coal phase-out programme which targets an end to the fuel’s use for power generation as early as possible.

With the economics pointing towards this being feasible before the end of this decade, the country should seriously consider embracing the chance to move to the forefront of global action in tackling the climate crisis.

Financing the Transition from Coal to Clean Energy

By Tamara Grbusic, Koben Calhoun, Paul Bodnar at Rocky Mountain Institute

It is becoming clear that an accelerated coal-to-clean transition in the global electricity system is both necessary and feasible. Commitments to cease new coal investments are critical in the near-term but insufficient to meet global emissions reductions required by the end of this decade.

Innovative financial mechanisms have a critical role to play in smoothing the just and inclusive transition from coal to clean energy. 
Innovative financial mechanisms have a critical role to play in smoothing the just and inclusive transition from coal to clean energy. 

According to Carbon Brief, any viable pathway to 1.5°C before 2030 requires a rapid decline in coal emissions. Coal transition needs to be completed in OECD countries before this decade is over and in the rest of the world by 2040. At the same time, economic viability of operating coal plants is declining rapidly: by 2025, 78 percent of coal plants globally will be more expensive to operate than building new renewable energy with storage. And yet, global coal transition within 20 years is far from a foregone conclusion.

Coal Phaseout Around the World

Governments are slowly starting to shift their attention to the phaseout of existing coal. Nearly 60 percent of operating coal across developed countries has either retired since 2010 or is scheduled to retire by 2030. President Biden recently announced that the United States should have 100 percent clean energy by 2035. In the EU, 15 countries have made coal phaseout announcements, 14 of which occur before 2030. Peru committed to complete coal phaseout by 2022. Canada has had a coal-free-by-2030 commitment since 2018.

And yet, these countries represent only a portion of the global coal fleet. The majority of coal plants worldwide still have no phaseout date. Ambition and commitments for a decisive coal transition must grow rapidly if we are to maintain any hope of aligning with a 1.5°C pathway. The most prominent organization working globally on the issue of government commitments to transition from coal is the Powering Past Coal Alliance (PPCA), a coalition of stakeholders, including governments, subnational entities, and businesses, committed to transitioning away from coal-powered energy in a sustainable and inclusive way.

PPCA has just completed its first global Summit. The Summit’s overarching goal was to bring together governments, academics, and investors, as well as energy, health, and just transition experts to enhance and accelerate international commitment to global coal phaseout in the lead-up to COP26 this November. The Summit introduced ten new PPCA members and hosted various sessions that explored practical ways in which countries can forge viable and holistic pathways away from coal. 

To support this dialogue, RMI organized and led a panel webinar titled “Exploring Financial Mechanisms for Early Coal Retirement” (recording available below).

 

The Critical Role of Innovative Financing

RMI’s event brought together stakeholders from governments, public finance institutions, the private sector, donor countries, trade unions, and utilities, in addition to experts from Poland and South Africa, to share their perspectives and experiences from working on approaches to an inclusive coal transition.

Danish Climate Ambassador Tomas Anker Christensen opened the session by urging nations to have a detailed plan, asset by asset, as well as precise policy measures, to enable policymakers and investors to make the right decisions and create viable coal transition plans. He stressed that what developed nations are doing will be of little importance unless everyone else joins the coal transition movement.

Participants elaborated on multiple successful mechanisms already in practice for an early and just coal phaseout, including the following:

  • Uday Varadarajan, principal at RMI, gave an overview of multiple mechanisms already in use around the world for an accelerated coal transition that include appropriate support for workers in the coal industry to reskill and transition to sustainable sectors, including ratepayer-backed securitization.
  • Colorado State Senator Christopher Hansen provided a more in-depth use case for securitization, explaining its application in Colorado and the process for securing buy-in to pass the legislation. He highlighted that securitization allowed the state to address parallel issues: replacing dirty, uneconomic coal plants and building communities, while also handing out savings to ratepayers as green alternatives became cheaper than incumbent coal-powered electricity.

But securitization is far from the only financial approach to enable coal transition while supporting workers and communities.

  • Fernando Cubillos, head of energy at IDB-Invest, explained the mechanics behind a carbon finance approach used in Chile, in collaboration with Engie, to retire coal plants and replace them with clean energy.
  • Donald Kanak, chairman of Prudential Insurance Growth Markets, gave an overview of energy transition mechanisms and their applicability to emerging economies. Emerging economies are the home of most existing and planned coal-fired electricity and therefore the key to an accelerated global energy transition.
  • Mafalda Duarte, head of Climate Investment Funds (CIFs), provided an overview of the CIFs’ Accelerating Coal Transition Investment program. She stressed the growing role of MDBs in coal phaseout in developing countries and explained that focusing only on building new renewable energy will not be sufficient to meet our climate objectives.

The second half of the panel centered around practical applications of these financial mechanisms in new geographies that rely heavily on coal, such as Poland and South Africa.

Grove Steyn, managing director of Meridian Economics in South Africa and Pawel Czyzak, head of energy modeling at Fundacja Instrat in Poland provided helpful (and hopeful) backgrounds on South African and Polish opportunities and challenges for coal retirement, highlighting possibilities for action and the importance of international community engagement and support.

Alison Tate, director of environment and social policy at the International Trade Union Confederation, ended with a pledge to put people first and ensure just transition for workers and communities. “We need to worry about stranding people, not just stranding assets,” Tate said. “We have to be wary of intergenerational unemployment as a consequence of coal phaseout and its effect on workers and communities.”

A Sustainable Way Forward

Innovative financial mechanisms have a critical role to play in smoothing the just and inclusive transition from coal to clean energy. They can help address political barriers, accelerate capital flowing to clean energy infrastructure, and, most importantly, ensure we continue to invest in people and communities. Finance is, however, only one part of the broader set of actions and activities needed to put global coal use on a pathway to 1.5ºC.

Building on the ideas, experiences, and challenges shared by the group of leaders who participated at the Summit, RMI is focused on advancing our work on innovative financial mechanisms. We will be partnering with governments, financial institutions, utilities, and other industry and labor experts to develop new financial mechanisms, evaluate their application in different markets and geographies, and scale our insights through global platforms, programs, and networks.

This article was originally published on RMI.org on 16th March 2021.

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Economics drive coal phase-out in Central and Eastern Europe

By Katherine Poseidon at Bloomberg NEF

Poland, Czechia, Romania and Bulgaria are the European Union’s most coal-reliant nations that have yet to commit to a plan to phase out the fuel. However, to lower the cost of their power systems, these countries could significantly accelerate the pace of transition from coal to clean energy in the next decade, according to a report released on July 6 by BloombergNEF, with the support of Bloomberg Philanthropies.

Poland, Czechia, Bulgaria, and Romania can become leaders in Just Transition and switch from coal to clean while contributing to industrial leadership of Europe.
Poland, Czechia, Bulgaria, and Romania can become leaders in Just Transition and switch from coal to clean while contributing to industrial leadership of Europe.

Following the least-cost power sector development path outlined in the report would allow these four countries to halve their power sector emissions, attract 45 billion euros in clean energy investment and create 45,000 jobs, while supporting Europe’s green recovery and climate efforts.

BNEF’s report focuses on Poland, Czechia, Romania and Bulgaria, where coal accounts for a significantly higher share of electricity generation than the EU average of 19%.

Figure 1. Capacity mix makeup

Source: Entso-e, European Commission, Eurostat, NECPs, IEA. Note: EU power mix numbers refer to 2018.

These four countries are currently responsible for a quarter of EU power sector emissions. The EU’s ambitious climate goals in the coming decade will not be achievable without their contribution. Poland, Czechia, Romania and Bulgaria can play a significant role in the EU’s energy transition through emission reduction associated with phasing out coal, while also growing their own economies.

In order to identify where emission reduction opportunities lie, BNEF’s least-cost scenario models an optimized energy mix for Poland, Czechia, Romania and Bulgaria through 2030. The modelling reflects current market and regulatory conditions and assumes that no policy changes will be introduced, instead looking at system cost, allowing the power mix to evolve over the next decade. The resulting scenario is based only on the existing pipeline of projects, and current EU Emission Trading System regulations.

Economics alone are piling pressure on coal assets, leading to the closure of half of the existing coal capacity by 2030 in the least-cost scenario. Were the EU to adopt more ambitious targets, and reform the current EU ETS accordingly, then closures are likely to happen much faster.

The share of renewables generation delivered by this least-cost scenario far exceeds what the countries are currently aiming for. By 2030, Poland, Czechia, Romania and Bulgaria could reach a 47% share of renewables generation, compared to 31% in the scenarios laid out in their National Energy and Climate Plans.

Figure 2. Electricity generation mix in the least-cost scenario

     

Source: BloombergNEF

The risk of adhering to lower targets and failing to adopt a coal phase-out plan is significant. Clear policy making and target setting will be necessary to mobilize the nearly 50 billion euros of renewables investment required to bring more than 50GW of clean energy online.

Coal is increasingly uneconomic, so by continuing to rely on the fuel, utilities, public finance and taxpayers will bear unnecessary financial burdens. The performance of Polish utilities reflects the pressure on coal, as share prices have declined over the last several years due to the companies’ exposure to the fuel, compared to market peers.

Figure 3. Share price of Poland’s top four utilities, compared with market peers

Source: Bloomberg Terminal

The failure to plan for a coal phase-out is also to the disadvantage of communities that rely on the fuel. The socioeconomic impact of coal closures laid out in BNEF’s least-cost scenario is significant. With further closures likely to be needed to meet the EU’s higher 2030 climate target, policy planning will be essential to ensure that coal regions are not left behind.

EU member states that adopt more ambitious 2030 plans, including for coal phase-outs, can make use of EU support for mitigating the socioeconomic effects of coal closures. Poland, Czechia, Romania and Bulgaria are all poised to benefit from the EU’s Just Transition Mechanism. However, to receive any of the almost 18 billion euros in direct funding, these member states will need to develop plans in line with EU decarbonization goals. This will very likely require a coal phase-out plan.

Frans Timmermans, the European Commission’s Executive Vice President, has emphasized the need for a just transition, speaking at the report launch.:

“To become the world’s first climate neutral continent, we have to turn the page on coal. Letting go of an industry that has provided jobs for decades will not be an easy process but Europe is ready to support it. Poland, Czechia, Bulgaria, and Romania can become leaders in Just Transition and switch from coal to clean while contributing to industrial leadership of Europe.”

Never before have the interests of Europe’s coal regions better aligned with the common goals of the EU. The decarbonization of Europe’s remaining coal-reliant power systems creates a need for billions of euros of clean energy investment, which can also spur the green recovery and bring the EU closer to climate neutrality.

The EU has the opportunity to act as a global leader in delivering a ‘just transition’ within its most coal-reliant member states. Lessons from moving away from coal, while mitigating the socioeconomic impact, can serve as an example for other countries and regions.

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Coal power retirement could save $100 billion

By Paul Bodnar at Rocky Mountain Institute
Matt Gray at Carbon Tracker Initiative
Steve Herz at

Renewable energy and storage is now so cheap that switching the world from coal to clean power would pay for itself by 2022 and would save over US$100 billion annually by 2025, shows a new report released on 30th June by PPCA partners Rocky Mountain Institute and the Carbon Tracker Initiative, as well as the Sierra Club. Replacing uncompetitive coal with clean energy would free up resources to pay for a just transition for workers and communities, as well as help reboot economies, create new jobs, improve health, and reduce carbon emissions, boosting the COVID-19 recovery.

New analysis shows the global transition from coal to clean energy has reached a financial tipping point
New analysis shows the global transition from coal to clean energy has reached a financial tipping point

Based on a global analysis of nearly 2,500 coal plants, we find that simply continuing to operate 39% of existing coal capacity worldwide is already more expensive than building new renewables and storage, even before the health and environmental costs of coal are considered. This number will nearly double to 73% in 2025, as both renewable generation and storage technologies are becoming less expensive every year.

Replacing uncompetitive, polluting coal with cheaper clean energy should be a no-brainer. Yet, despite coal’s declining competitiveness, long-term contracts and noncompetitive tariffs insulate coal plants from competition with cheaper renewables, meaning that countries are stuck operating them.

We present a three-step plan for how governments and public finance institutions – such as green banks, multilateral and national development banks, and development finance institutions - can accelerate the retirement and replacement of coal power and spur a just transition toward a cleaner and more resilient energy future.

The first step is to refinance coal assets to pay off investors whose returns currently depend on the coal plant continuing to operate. Recommended refinancing mechanisms include asset-backed securitization, ratepayer-backed bond securitization, and green bonds – tools that free up capital that would otherwise be locked in coal assets.

The second step is to reinvest part of the new capital raised through refinancing in clean resources to allow coal plant owners and investors to replace coal returns with clean returns. The third step is to use part of the new capital to support a just transition of workers and communities.

How much would this plan cost? For plants that are already uncompetitive today, phasing-out and replacing them requires little or no additional public funds and brings substantial savings.

For example, in the European Union, 81% of the coal fleet is already uncompetitive, rising to the entire fleet in 2025. If Europe’s uncompetitive coal were retired and replaced this year, consumers would save US$10 billion each year going forward. That number would rise to US$15 billion if these plants were retired and replaced in 2022, and US$21 billion in 2025.

Phasing out the 60% of global coal capacity that is still competitive today may require additional public resources, but only in the short-term. These resources can be provided through incentive-based concessional finance tools, such as carbon bonuses (payments for emission reductions) or debt forgiveness allocated via reverse auctions.

Replacing coal power will not be without short-term costs in some regions, but globally, the three-step plan presented in the report has the potential to bring over US$100 billion in annual net savings if completed in 2025.

These funds can be used to support workers in coal industry to reskill and transition to sustainable sectors.

Now is the perfect moment for governments and public finance institutions to take action - the need to allocate stimulus spending as part of COVID-19 economic recovery presents a special opportunity to accelerate the coal-to-clean transition. The proposed measures will not only save money, but also boost efforts to build a more stable, sustainable, and resilient world post-COVID-19. Given how long it can take to negotiate phase-out agreements, the time to start structuring these deals everywhere is now.

This article is part of a PPCA special insight series on the coronavirus crisis and its impact on the transition away from coal power generation.

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Coal cannot be the answer to Covid-19

By Powering Past Coal Alliance

As the world recovers from the impacts of the pandemic, we have a once-in-a-lifetime opportunity to put the global energy sector on a clean, low-carbon, resilient growth trajectory.

Renewables are outperforming coal around the world.
Renewables are outperforming coal around the world.

The Covid-19 pandemic has accelerated the global decline of coal. Coal-fired power generation is set to fall by more than 10% this year, the largest decrease on record. But unlike the lives that have been lost or changed forever by the pandemic, this historic drop is only temporary.  As the global economy recovers, coal use will likely rebound.

The real, long-term impact of the pandemic on coal phase-out will be determined in part by the nature of the recovery packages that governments around the world put in place in the coming months.

If government stimulus is used to prop up existing coal facilities, or spurring new coal capacity, it will lock countries into environmentally and financially unsustainable coal power for decades to come, undermining global climate action and the transition to a low carbon economy.

Using public money to sustain or expand coal power is economically, socially and environmentally harmful.

Conversely, economic recovery measures should be aligned with global climate efforts, support a just transition for all, and build a solid foundation for more resilient and sustainable societies.

Green recovery packages can be an opportunity to prompt a steep decline in coal power generation, given their massive, once-in-a-lifetime scale.

Renewables are the cheapest source of new bulk electricity in countries representing two-thirds of the world population and 71% of global GDP. In virtually every market, coal is no longer the cheapest source of new generation.

Cheaper renewables and weaker demand growth are also increasingly causing a large number of gas and coal-fired power stations to stand idle, with the global coal fleet running at just above 50% of capacity in recent years. This trend adds to the risk of seeing coal investments become stranded assets. In recent years, we have seen over 100 leading financial institutions move away from financing coal-fired power plants. This is just good business sense.

Investing in coal power would disregard the growing climate crisis. We are faced with a significant opportunity to prepare our societies for the future. By taking ambitious action on energy transition now, we can avoid another massive disruption, this time caused by climate change. If we are to meet the Paris Agreement goals and avoid the most dangerous impacts of climate change, EU and OECD countries must phase out unabated coal-fired electricity generation no later than 2030, with the rest of the world no later than 2050. PPCA members are working collectively towards this goal.

Eliminating coal power generation will also bring tremendous benefits for public health and quality of life. As air pollution levels plummet given current sharp reductions in coal and oil burning, a recent study found that 11,000 air pollution-related deaths will be avoided in Europe. This shows what can be achieved with a shift away from coal towards cleaner energy sources.

In the wake of this pandemic, instead of reviving polluting coal energy production, governments should encourage the energy sector to accelerate the clean energy transition.

Recovery measures can be an opportunity to incentivize a major expansion of clean power and a retirement of coal. This will help create green jobs, uplift communities, and rebuild economies that are stable, resilient and sustainable.

A recent report for the Oxford Review of Economic Policy found that green projects create more jobs, deliver higher short-term returns per dollar spend and lead to increased long-term cost savings when compared to traditional fiscal stimulus. Effective recovery measures that support climate and economic goals include investments in renewable energy, storage, grid modernisation, energy efficiency retrofits, worker retraining away from fossil fuel industries, reforestation and sustainable agriculture, and research and development into clean technology.

Governments can further accelerate the transition by financing the retirement of coal power plants, in particular where the oldest and most polluting plants are operating in markets with oversupply. The shift must be accompanied with social protection and security for the affected workers and communities.

Public support for investing in climate action as a post-coronavirus recovery is high across the world. Momentum is also building among public and private sector actors. Powering Past Coal Alliance co-chairs and members, both government and businesses, are committed to doubling down to spur a green recovery. International collaboration, support and knowledge sharing will be critical to ensure that the stimulus funding accelerates the coal-to-clean transition.

The Powering Past Coal Alliance stands ready to support governments in shaping and implementing recovery plans that build a renewed, sustainable progress and prosperity across the world - fueled by clean electricity in place of coal.

This article is part of a PPCA special insight series on the coronavirus crisis and its impact on the transition away from coal power generation.

Spanish utilities aim to decarbonize faster

By Emma Champion and Ben Vickers at Bloomberg NEF

Image via Bloomberg
Image via Bloomberg

Spanish utilities will decommission half of the country’s 10GW coal capacity by June 2020, as EU emissions regulations bite. Only four power plants plan to invest in retrofits to comply with new standards, while closure requests for four other plants have been approved. The speed of phasing out the rest of the coal fleet could, however, hinge on any further policy measures once the new socialist government takes office following their victory in Spain’s general election on April 28.

Previous Spanish governments had attempted to block coal plants from closing and propped up overcapacity with targeted capacity payments. But the recent closures of domestic coal mines at end 2018, and approvals for coal closures signalled a change of approach.

Figure 1. Coal plants in Spain by status and size (Source: BloombergNEF)

After first taking office as a minority administration in 2018, the socialist government announced its desire to unlock $270 billion investment in the energy transition. Utilities have responded with their own plans and are beginning to reshape their investment strategies to decarbonize their generation assets faster than ever.

Endesa SA, one of Spain’s biggest coal operators, wants to build out its renewables strategy to offset thermal plant closures. Meanwhile, Iberdrola SA, Spain’s largest power company and a member of the Powering Past Coal Alliance, is set to have closed all its coal-fired power plants by June 2020. The company says its strategy of lowering emissions, which has seen it shutter 17 thermal plants so far while investing heavily in renewables, is aligned with long-term trends.

“We have analyzed nine megatrends that are all pushing toward decarbonization of the economy", Carlos Salle, head of climate change at Iberdrola, said in an interview with BloombergNEF. “Even with some governments against this change, like now the U.S. administration, all these megatrends say you have to push for the decarbonization of your company and of the economy.”

The draft national energy and climate plan published in February 2019 by Spain’s then minority socialist government shared this view and proposed that Spain should phase out of coal power generation by 2030 at the latest.

This accelerated transition aligns with the trends revealed in BloombergNEF’s New Energy Outlook 2018: that Spain can reduce its emissions from around 100 million tons of CO2 equivalent today, to virtually no emissions by 2026. Our analysis shows that renewables, already the cheapest new-build source of electricity in the region, can provide around 80% of electricity generation by 2026 and over 90% ten years later, on a least-cost basis. Iberia’s exceptional renewables resources (including the fact that solar is well suited to the peninsula’s consumption profile) and higher carbon prices, combine to deeply undermine the economics of coal as a power source.

Figure 2. Iberia power sector emissions (Source: New Energy Outlook 2018)

Figure 3. Iberia power sector emissions generation (Source: New Energy Outlook 2018)

Regions affected by the decline of coal as a source of power should be reconverted to develop industries and jobs in clean energy, Salle said. Authorities in these areas and European Union institutions should limit subsidies and help them take advantage of new opportunities as the energy sector cleans up, he said.

After creating a new Ministry for the Ecological Transition, with responsibility for both energy and climate change, the socialist government set the tone for Spain’s coal phase out by signing a framework agreement for a ‘fair transition’ from coal with Spain’s mining unions on October 24 2018. To bridge the closures, the government is providing 250 million euros in public financial support for workers and businesses affected by the transition away from coal in these autonomous regions over 2019-23. Some utilities are following suit with coal power plant closures: Iberdrola is paying workers to shut down operations through measures such as early retirement packages and training in clean energy jobs, while Naturgy is planning to retain some employees previously at Meirama coal plant to develop a 65MW wind farm and a cogeneration from waste facility.

Where policy lags, decarbonization of the economy will be pushed through by consumer choices, especially in cases where companies can be differentiated by their carbon emissions and other environmental indicators, according to Salle. Government measures should reflect the “polluter pays principle” in a more ambitious way, he said. Corporate emissions targets set for 2050, when current executives will no longer be at a company, are not effective -- they should be set for the shorter term so managers can be held to account, Salle said. There also needs to be a clearer link between corporate compensation and environmental performance, he said.

Interview: Carlos Sallé, Senior Vice-President of Energy Policies and Climate Change at Iberdrola

The following interview is edited for length.

Q: The last two coal plants Iberdrola operates in Spain, in Asturias and Palencia, are to be closed in the next couple of years. How much of a watershed is this for the company?

A: When we announced the closure of our last two coal-fired power plants in Bonn, at COP[23] in November [2017], everybody received this very well. That is except for our own [previous] government in Spain, which started a fight against us, saying we wanted to close the plants for other reasons when the reality is that this is part of our long-term strategy. We have already shut 17 plants; we are developing a lot of renewables and coal is just not part of our strategy.

We have been pursuing this strategy for 17 years and have invested a lot in renewable energy. When we started, environmentalists would say it was just green washing, but with the constant drip of change, and then suddenly this decision, they and other parties realized, well, maybe Iberdrola was telling the truth.

Q: Some companies have adopted a relatively fast route toward decarbonization, and others are lagging. Iberdrola says decarbonization is an opportunity. Where are the opportunities and where will growth come from?

A: There are lots of opportunities. We have analyzed nine megatrends that are all pushing us towards the decarbonization of the economy. So even with some governments against it, like the current U.S. administration, all these megatrends say you have to push for the decarbonization of your company and of the economy. In that sense we are not only divesting the older assets but also investing more in renewables. We are also looking to strengthen our positioning in the digitalization of our energy systems and the empowerment of consumers. Decarbonization leads to more renewables and more smart networks to manage the increased penetration of renewables and the empowerment of consumers.

Q: Carbon emission allowances in Europe are at more than 20 euros a ton – what difference is this going to make to the pace of decarbonization in a country like Spain?

A: The rise in CO2 prices is an important issue, because it is relevant to changing the way consumers think about the environment. But there is one megatrend we have looked at that will have a greater impact than carbon prices, and that is air quality. That’s because poor air quality produces problems that are very close to citizens. If there is a general health issue you will be banned from driving in city centers, so this signal is very close to you.

Also, the institutions responsible for setting policies for air quality in cities are more flexible than federal governments or multilateral bodies like the United Nations. We can see that in all the initiatives like the C40 [network of cities tackling climate change]. For example, in Madrid we have new rules on emissions and these impact on citizens’ decisions such as what their next car will be. Manufacturers realize that they will have problems in the future, because maybe they are not as fast as competitors in adapting. So air quality will be a powerful way of making changes happen.

Q: Air quality is one clearly measurable indicator for citizens. From the corporate perspective, is there an equivalent single message or pressure point that can bring about change?

A: My mantra is that the cost of decarbonization is less than the cost of non-decarbonization. At the moment you are not seeing the cost of air pollutants, but you have people going to hospital because of pollution. In Spain, we have all these storms that never used to happen in the past. They have completely destroyed some coastal assets, and Spain is a country of tourism. This is due to climate change. This cost has to be allocated to those people who are causing the emissions. We have to raise awareness.

There are two ways of making these changes. One is policy, but not just with regards to CO2, as we have the other pollutants as well. And the other one is through raising awareness. Consumers make billions and billions of decisions each day that can change the problems of the planet.

Q: What are the signals that need to be given to the current government in Spain?

A: We have presented to the previous and the current government in Spain, showing that we can decarbonize at least 90 percent of the economy, 97 percent of the energy mix, with consumption efficiency and changes to production while at the same time benefiting the economy, security of supply and the environment. This is the first time a big electric company has said that it’s possible to have close to 100 percent of generation fully decarbonized. This is very relevant for the government, because now it’s not just environmentalists talking about this, and we have provoked a reaction from our competitors who have still to define their position.

The government received the signal that this is feasible, it’s an opportunity, and that we have to make alliances to make this effective. With coal, they know that switching is not a problem since there’s plenty of gas capacity installed in Spain, and neither is price. On the contrary, this is all an advantage for our health. And we told them we have to solve the problems of these vulnerable regions, like the mining regions in Spain. In the green economy we have a lot of new products, components for wind, solar, for batteries, heat pumps, EVs, or LEDs … and we have analyzed what is the best way to introduce into these regions elements from this green economy. The regional administration, the national government and the EU have to provide solutions to minimize the costs.

We have to stop talking about the impossibility of closing coal plants because of the social problems it would cause. In Spain there are just 2,000 jobs in coal mining. We have given assurances to all our employees that their jobs will be preserved as we did in all the other plants we closed. And for indirect jobs, you have to analyze that and develop a plan.

For example in Lada, in Asturias we are closing a coal plant. But nearby there is a harbor, with roads and the right infrastructure to develop new industry, and you have to analyze what is the best way of using this for new opportunities.

It’s very difficult to defend this polluting activity that is bad for the environment, bad for the region, for the air quality and even for competitiveness.

Q: But are there any examples where they have managed to reconvert a regional economy that depended on coal?

A: There’s an example in Spain. It’s Navantia, a state-owned shipyard that normally just built ships, and we have convinced them that by changing their processes a bit they can construct some parts of our offshore wind farms. They internalized that and after a while they have started producing jackets for offshore turbines and substations. We have placed some contracts with them, and we know that with this new line of business Navantia has won contracts from other companies. So in Spain, in Asturias, Galicia and in Cadiz, they have created jobs and diversified production in the new economy.

Q: Iberdrola has lots of hydropower and you invested in renewables early on, so your path to decarbonization is very particular. In Poland or Germany the dependency on coal is much stronger and they have more than 2,000 miners.

A: The EU has some funds dedicated to this. The approach will be the same, maybe the process will be more gradual. But in the end technology has given us a solution for these problems. In the past it was difficult, but now technology has given us a better solution. You have to convince these regions to gradually transform their economy – to introduce the manufacturing of solar components or something like this, opportunities that are more acceptable in terms of skills required that are best for the region.

Q: Iberdrola has been participating is many international events around climate change. What is your role there?

A: Following the Paris agreement, it was clear that an important part of the solution is an alliance of the world’s businesses. It is important for these agreements not just to receive the support of NGOs but of large energy companies. We have presented at all these events and have contributed to drive awareness on climate issues. Those taking policy decisions see that a very relevant actor in the power sector has made some relevant, ambitious proposals. We are asking the IEA to extend their monitoring of CO2 emissions to include air quality, which is an issue for oil and coal companies. Also, we are asking governments that the polluter pays to be the main driver of change.

In any case, we are changing the soul of our company. Many people say companies have no soul, but governance is the virtual soul of the company, and we are introducing sustainable development goals into our mission, vision and values, with climate change as the main driver. We can link remuneration for board directors and senior management to fulfilling commitments on CO2. It also sets our position with respect to competitors.

We have presented commitments for 2020, 2030, and 2050. Many companies are just presenting goals for 2050, which is a sort of greenwashing because the managers won’t be here in 2050. Our commitments are for 2020, when the managers will be the same.

Coal-to-gas switch slashes U.S. power sector CO2

By William Nelson at Bloomberg NEF

Image via Bloomberg
Image via Bloomberg

Grid operators deploy generators in order of increasing short-run marginal cost. They use first the power that is generated at least cost and progress up a power supply curve called a ‘merit order’, adding generators to meet electricity demand at the lowest possible cost. This concept dictates how power plants operate hour-by-hour and underpins wholesale price formation in deregulated markets. In the U.S., power sector emissions have fallen 25% since 2008, in large part due to the way cheap natural gas has disrupted merit orders. Gas turbines now run more cheaply than plants burning coal, and therefore run more often.

The switch from high-carbon coal to lower-carbon natural gas is a fast-acting abatement opportunity available on many grids worldwide. Here we examine the mechanics behind coal-to-gas fuel-switching in the US and describes its impact on carbon dioxide emissions.

  • Coal-fired generation dropped 40% from 2008-17, while coal capacity fell 13%. The decline is being propelled largely by lower utilization rates rather than plant closures: the average U.S. coal plant operated with a capacity factor of 49% in 2017, down from 67% in 2008.
  • Cheap natural gas is the primary reason for coal’s decline. Every time a gas turbine fires up in place of a coal unit, overall emissions fall by an average of 0.6tCO2e/MWh. This is because gas is cleaner than coal and because gas turbines burn fuel more efficiently.
  • Gas burn has expanded dramatically since 2008 – at the expense of coal burn, as the figure below shows. This fuel switch has done more to curb U.S. carbon emissions in the past decade than any other single factor, including new renewable build.
  • Operational fuel switching, where one plant firing up in place of another, is entirely reversible. This is not the case with structural switches such as coal plant retirements or renewable installations. But structural switches take time to accumulate while operational switching can happen overnight.

Figure 1: U.S. power mix and power-sector emissions (Source: BloombergNEF, EIA Form 923)

Drivers of abatement from the U.S. power sector

The U.S. serves as a useful case study for understanding fuel-switch dynamics because of the extreme price-driven shift from coal to gas in recent years. It helps that U.S. power markets are relatively ‘pure’, in the sense that in practice, power fleet behaviour aligns closely with economic theory.

The figure below tracks greenhouse gas emissions from the U.S. power sector (black line) and estimates the reasons for year-on-year changes (stacked columns). Overall, since 2003, the leading source of GHG emissions reductions comes from ‘fossil fuel switching’, that is the replacing one form of fossil-fired generation with another – primarily coal to gas.

Figure 2: What drives U.S. power-sector emissions (MtCO2e/month; 12-month rolling averages). (Source: BloombergNEF, EIA Form 923)

The drivers behind power-sector emissions fluctuations:

Overall, emissions dropped 25% from 2008-17, in response to the following drivers:

  • Renewables: Steady year-on-year growth in renewable energy generation stifles fossil burn, making renewables the only ‘driver’ that consistently reduces annual emissions. All other ‘drivers’ are reversible, sometimes reducing, sometimes raising annual emissions.
  • Hydro: Hydro is not a large part of the overall abatement story because hydro capacity has not changed much since the 1980s. Instead, annual fluctuations in precipitation cause high-hydro and low-hydro years – particularly in the Northwest – with knock-on effects for fossil burn.
  • Nuclear: Like hydro, nuclear capacity has been mostly stable over the past two decades, though generation has oscillated slightly, due mostly to refueling schedules. Only a handful of new build and retirement decisions have altered annual emissions over the past two decades, though this is expected to change. Waves of retirements are expected; and this will render nuclear a ‘positive driver’ of U.S. power-sector emissions. Emissions will increase as reactors retire.
  • Fossil fuel switch: The U.S. fossil fleet is getting cleaner. Fossil-fired emissions factors fell 19% from 2003-18, from 0.86tCO2e/MWh to 0.70tCO2e). There are several reasons for this:
    • Coal-to-gas: Switching from coal- to gas-fired generation reduces emissions because gas is cleaner than coal and because gas turbines are typically more efficient than coal plants. The widespread coal-to-gas fuel switch that has unfolded on U.S. grids is foremost an ‘operational’ phenomena: gas units ramp up generation, neighboring coal units ramp down. This process is a function of the relative costs of gas and coal, and is entirely reversible. (Hence the sometimes-positive, sometimes-negative impact on U.S. emissions.) 

      Permanent fuel-switching can occur when coal plants retire or convert their kits to burn gas. But coal plant retirements have had a smaller impact on U.S. emissions reductions than utilization rates, and permanent retrofits are relatively rare.
    • Gas-to-gas: Gas-to-gas fuel switching occurs when one gas plant fires up instead of another. A growing fleet of efficient, combined-cycle gas turbines (CCGTs) is displacing generation from older, inefficient open-cycle gas turbines (OCGTs), reducing emissions in the process. Gas-fired emissions factors have fallen 15% since 2003 (0.47-0.41tCO2e/MWh).
    • Coal-to-coal: U.S. grids have retired some of their least economic, least efficient coal plants in the past decade. When a coal plant retires, its output is immediately replaced with existing coal or gas.
  • Load: Electricity demand influences emissions in an obvious way: higher load equates to higher emissions, all else being equal. Overall U.S. electricity demand has held flat since 2008 for a variety of reasons, including energy efficiency, saturation in the heating, ventilation, and air conditioning (HVAC) market, and the shift toward a service-oriented economy.

The story behind power-sector emissions fluctuations:

  • 2003-08: Deregulation in the early 2000s encouraged a boom in new combined-cycle gas turbine development, and this led to a prolonged gas-to-gas fuel-switch (of newer plants replacing older ones) that helped keep emissions in check. (This is represented by the negative purple bars.)
    But the economy was booming, and electricity demand grew more than 1% per year. Rising demand for electricity meant more fossil fuel combustion. Emissions peaked in 2008, which was also a dry year with low hydro output, just before the onset of the financial crisis.
  • 2009: Electricity demand plunged 4% in 2009, with the economy in the grips of the financial crisis. Emissions plummeted as load dropped, only to rebound the following year when the load reverted to ‘normal’ levels.
    Something else was special about 2009, though: it coincided with the beginning of a period of parity between coal and gas prices. Pre-2009, coal was definitively cheaper than gas; since then, the two fuels have faced tight competition, frequently contributing to reductions in power-sector emissions (‘negative purple’). This is associated with the onset of the U.S. shale boom.
  • 2012, 2016: Emissions fell drastically in these two years because of deep coal-to-gas fuel switching. This process was amplified by atypically warm winters. For example, in a ‘normal year’, when the weather gets cold, the U.S. burns through its natural gas reserves to heat homes and businesses. But in 2012 and 2016, the U.S. gas industry emerged from wintertime with an excess of stored natural gas. This caused gas prices to collapse, gas turbines to fire up, and coal plants to ramp down.
  • 2014: Emissions climbed in 2014 following an exceptionally cold winter. The so-called ‘Polar Vortex’ brought record-low temperatures in the winter of 2013-14. Gas storage levels were depleted; gas prices surged; the coal-to-gas fuel-switch reversed. Coal plants thrived.
  • Regional differences: All grids are exposed to the drivers outlined above, but in different proportions. For example, the deepest emissions reductions of the past decade occurred in PJM and the Southeast, where renewable build was modest but coal-to-gas fuel-switching was particularly pronounced. Meanwhile, Texas and California absorbed the most wind and solar build, respectively, but power-sector emissions from these two states has remained relatively unchanged.

‘Merit-order’ mechanics

Merit orders are best interpreted with a basic understanding of the classic supply-versus-demand curve taught in Econ 101. ‘Merit orders’ are the name for the electricity supply curve created by a fleet of power plants. This concept unlocks an arsenal of insights that can be used to understand fuel-switching and power plant valuation.

  • Every hour, grid operators take stock of their pool of generators and decide what to turn on and what to turn off. They try to meet electricity demand as cheaply and reliably as possible. Merit order diagrams help visualize so-called ‘optimal economic dispatch’ by ranking units in order of short-run marginal costs – that is, the variable costs of producing an incremental megawatt-hour of electricity, ignoring ‘sunk’ costs such as fixed operation and maintenance and capital expenditures for each generation unit.
  • The most important factors governing short-run marginal costs for generators are fuel prices and plant efficiencies. For example, wind and solar farms do not burn fuel, so they generate cheaply and sit at the front of the merit order. This is why wind and solar farms are typically dispatched whenever available. Meanwhile, fossil-fired power plants must ‘compete’ with one another for priority. Whichever unit can produce electricity most cheaply is dispatched first, and therefore more frequently. Cost-competition leads fossil plants to spend more available hours offline.
  • Short-run marginal cost-based supply curves are a fundamental concept of macro-economics. They are the ‘supply’ in the classic ‘supply-demand’ curve. Most power market designs and regulations seek to minimize cost, though there are numerous exceptions on global grids. Often, subsidies and overlapping policies distort dispatch decisions and cause plants to run sub-optimally.
  • Carbon pricing fits neatly within the framework of the ‘merit order’. Carbon taxes and cap-and-trade schemes simply alter emitters’ short-run costs, re-arranging the order of dispatch to prioritize cleaner generators.

Figure 3: PJM’s power supply curve: 2008 versus 2018 (Source: BloombergNEF’s Merit Order Marker: Interactive Dashboard)

Lessons from Figure 3

  • It should be clear from the figure above why oil-fired units are used sparingly. Oil is an expensive fuel so oil-burners, with high marginal costs, occupy the far-right of the merit order. They thus operate as ‘peakers’, which means they are used only during periods of extremely high demand, or during times of natural gas shortage.
  • Similarly, it should be clear why nuclear plants run baseload. Their variable costs are low (even though fixed costs are high). This places nuclear towards the front of the merit order, where it is dispatched 24/7.
  • The ranking of coal and gas is increasingly trickier to generalize:
    • In 2008, coal plants ran baseload while gas turbines operated as ‘mid-merit’ units. In practice this meant gas plants turned off at night while coal plants stayed online.
    • By 2018, coal and gas plants now ‘intermingle’ on the merit order. In PJM, the general rule of thumb is that CCGTs run baseload while OCGTs and coal plants run mid-merit.
  • Emissions have fallen precisely because coal has move towards the back of the merit order. The 2008-to-2018 comparison illustrates the rationale behind the dramatic 'fuel switch’ that has occurred over the past decade. In summary, falling gas prices reduced the short-run costs of gas plants, allowing them to undercut coal and switch positions on the x-axis of the merit order.

Short-run marginal cost (SRMC) for power plants

If we ignore transmission charges, ramping and run-time constraints, and other secondary factors, then power prices boil down to one simple equation:

Figure 4. Short-run marginal cost formula, for fossil plants

  • Variable O&M (in $/MWh) is a term that captures normal wear and tear associated with operating and maintenance for power plants. It can also include the variable costs of running environmental controls like sulfur dioxide scrubbers. This term is generally small (~$5/MWh).
  • Fuel price (in $/MMBtu) is the most dynamic factor in the short-run marginal cost calculation. For example, benchmark U.S. gas prices (at Henry Hub) fell from over $8/MMBtu in 2008 to under $3/MMBtbu in 2017. For comparison, benchmark coal hub prices range from $0.70/MMBtu in the Powder River Basin to $2.50/MMBtu in Appalachia. But hub prices alone do not tell the whole story: the costs of transporting coal is often as high, or higher, than the price of buying fuel at the hub. All-in, the average coal plant pays between $2 and $3/MMBtu for its fuel (hub price + transport costs).
  • Heat rate (in MMBtu/MWh) is an inverse-measure of plant efficiency, specifying how much fuel is needed per unit of electricity output. Heat rates for combined-cycle gas turbines hover around 7MMBtu/MWh; coal plants cluster around 10MMBtu/MWh.
  • Carbon prices (in $/tCO2e) apply in ten U.S. states spanning two separate cap-and-trade programs. In these states, short-run marginal costs of plants are boosted by the costs of allowances.
  • Carbon intensity of fuel (in tCO2/MMBtu) is a function of combustion chemistry. Natural gas emits ~0.05tCO2/MMBtu while coal emits ~0.10tCO2/MMBtu. When paired with the fact that coal units are typically less efficient than CCGTs, we see that coal plants emit more than twice as much CO2 as CCGTs. Because of this, wherever carbon prices apply, they hit coal plants harder than gas plants.

Coal-to-gas pricing dynamics

The figure below compares the relative economics of power, gas and coal over time. Specifically, it compares short-run marginal costs for a typical coal unit and combined-cycle gas turbines, using the formula from the merit order analysis above.

Figure 5: Short-run costs of coal and gas versus power prices – monthly averages ($/MWh). (Source: BloombergNEF’s Power and Fuel Pricing Dashboard, Bloomberg Terminal)

  • Power prices follow gas and coal prices. Note how the blue shaded area in Figure 6 follows the purple and black lines. This is because power prices are a function of the short-run marginal cost of the marginal generator – a combination of gas- and coal-fired units.
  • Coal-to-gas competition is amplified. Prior to 2009, coal units had definitively lower short-run costs than gas. Since then, prices have remained much closer to parity. This has allowed some gas units to undercut some coal units, each time reducing coal burn and emissions.
  • Dark spreads are in decline. ‘Dark spreads’ refer to operating margins for coal plants. For example, prior to 2009, when power prices hovered around $60/MWh and coal costs were $30/MWh, coal plants would net $30/MWh. Since then, falling power prices and dwindling dispatch opportunities have eroded gross margins for coal plants. This is why many face retirement: many coal plants now fail to earn enough money to cover their fixed costs of operation.

The EU ETS: Back in the spotlight

By Jahn Olsen at Bloomberg NEF

Image via Bloomberg
Image via Bloomberg

The European Emissions Trading System (EU ETS) is the largest carbon market in the world. It was set up to be a cornerstone of EU climate policy, but it is hard to argue that it lived up to its remit. Oversupply and an inflexible design has meant the market delivered far lower prices than necessary to push coal out of the generation mix. That could be about to change. The EU recently completed a reform aimed at bringing scarcity to the market by strengthening the Market Stability Reserve (which went live in January 2019), and by adding other supply curbing measures in the market’s design in 2021-30. Governments in coal-dependent nations such as Poland and Romania are already calling for the EU to intervene to cool the market

Why carbon pricing matters – fuel-switching

Cap-and-trade markets like the EU ETS set a limit on the total amount of greenhouse gases participating installations can emit. Each emissions allowance (EUA) gives the holder the right to emit one metric ton of CO2, or the equivalent in N2O or PFCs. The number of allowances decreases linearly by 1.74% of 2010 emissions annually, which widens to 2.2% in 2021. Companies have to surrender allowances for their emissions and can trade to ensure they have enough to cover their emissions. It is trading that makes carbon markets efficient as it allows the market to reduce emissions in the cheapest possible way.

Figure 1. Illustrative merit order without carbon price (Source: BloombergNEF)

 

Figure 2. Illustrative merit order with carbon price (Source: BloombergNEF)

It is generally cheaper to produce power from coal than from natural gas. This puts coal plants in front of gas plants in the so-called ‘merit order’ in markets without carbon pricing. The flipside is that they are also more polluting, emitting roughly twice as much CO2 per megawatt-hour compared to gas plants. With a high enough carbon price, gas will move ahead of coal in the merit order in a process called ‘coal-to-gas fuel-switching, reducing emissions.

Economic downturn and oversupply

Fuel-switching is the cheapest form of abatement in the EU ETS. But the market has been oversupplied since its 2008 restart, which has led to a negligible carbon price. The U.K. implemented a carbon price floor as a top-up to the EU ETS price, which contributed to the decline of coal in its power market, but the EUA price has not been high enough to have a similar impact in continental Europe.

Figure 4. European carbon price and inverse total number of allowances in circulation (Source: ICE, BloombergNEF)

European carbon price and inverse total number of allowances in circulation (Source: ICE, Bloomberg NEF)

There has been a strong inverse correlation between the cumulative oversupply, or total number of allowances in circulation (TNAC), and the price of carbon, since the financial crisis. This relationship somewhat broke down in 2018 as the price of carbon has gone up despite continued oversupply. The reason for the recovery is that a large number of speculators have entered the market on the expectation there will be scarcity in the future. 

The market’s oversupply is due to its inflexible design. The cap was calculated using verified emissions in the first trading phase (2005-07). The 2008-09 financial crisis led to a drop in economic activity and its associated emissions in Europe, however, and there was no measure in place to reduce supply in case of an unexpected drop in emissions. In the past few years, the EU has attempted to address the oversupply through multiple reforms, and supporters of a strong carbon market finally have a reason to be more optimistic. 

The market stability reserve

In early 2018, the EU completed a carbon market reform, changing the future framework of the EU ETS. The reform is seen as quite ambitious, and the market responded by pushing the price to levels not seen since 2008. The biggest reason for optimism is that member state auction supply is being curbed by the market stability reserve (MSR), which started operating in January 2019. 

The MSR will remove allowances from auctions if the TNAC is above 833Mt and reintroduce them to auction if it falls below 400Mt, finally bringing flexibility to the supply of carbon allowances. The reform has doubled the MSR intake rate to 24% from 12% of the TNAC in the first five years (2019-23) of its operation. The change means that the mechanism will be able to quickly balance the market, bring scarcity to the market and push emissions reductions in the power sector.

Figure 5. Market stability reserve flowchart (Source: BloombergNEF)

Market stability reserve flowchart (Source: Bloomberg NEF)

The MSR will remove 1,117Mt EUAs from auctions in the first three years of its operation alone, according to BNEF modelling. The market will be short on an annual basis from the year it becomes operational, quickly eroding the oversupply that has built up. This should push the European carbon price above 30 euros per metric ton by 2020 and keep it between 28 and 35 euros in the following four years. 

Figure 6. Historical and forecast EUA price (Source: BloombergNEF)

Historical and forecast EUA price (Source: Bloomberg NEF)

Gas generators will probably benefit from the high carbon price in the early 2020s. We estimate that new build renewables will become competitive with existing gas from 2022-23, and cheaper from 2024 onwards. As a result, wind and solar should be built on the back of a high carbon price in the mid-2020s, permanently reducing emissions in the power sector. 

Figure 7. Forecasted EU ETS impact on emissions (Source: BloombergNEF)

Forecasted EU ETS impact on emissions (Source: Bloomberg NEF)

It could be the time for the EU ETS to shine, if it is left to run its course under the current legislative framework. The difference in emissions between the no-ETS case and the ETS case above is 374Mt, around 350Mt of which is from the power sector – a 57% reduction in power sector emissions. That amounts to around 340TWh, equal to annual power generation on the Iberian Peninsula, if the replaced generation is a mix of lignite and coal (Assumes zero emission renewables replacing generation with an emissions intensity of 1,025g/kWh).

Coals downward trajectory in Europe

The writing is on the wall for coal in Europe, but it is not altogether clear if it will be the EU ETS or other policies that will have the largest impact on its demise.

The effectiveness of the EU ETS is vulnerable to overlapping policies and the market could drift back into irrelevance if large coal-dependent countries like Germany and Poland decide to completely phase out coal from their generation mix without reducing EUA supply equal to or greater than the resulting emissions reductions. A failure to adjust the supply of EUAs would lead to a lower price, and less EU ETS-driven abatement. In such a case, the EU ETS would act as a backstop to emissions rather than the primary driver of emissions reductions.

The good news is that EU member states are considering taking appropriate action to minimise the impact of overlapping policies. Germany, for example, is discussing the cancellation of EUA auction volumes equal to the emissions of the phased out coal plants. In fact, overlapping policies could make the carbon market even more ambitious. The German government, for example, has indicated that it will likely cancel gross emissions, rather than the net difference between coal and gas which will make the market shorter during the cancellation years. 

Perhaps the biggest threat to the EU ETS is pressure from coal-dependent EU member states and emissions-intensive industries. The EU has shown that it is not afraid to tinker with the carbon market if it deems that it is not performing as it would like it to. There’s a risk that the European Commission could initiate a reform to weaken the MSR or add more supply if the EUA price goes too high, too fast. Coal dependent countries will claim carbon costs are too detrimental to their competitiveness, and industries will point out that there is a risk of carbon leakage (Carbon leakage in this context means European industry relocating elsewhere due to high carbon prices in Europe).

The European carbon market could be on the verge of becoming the cornerstone climate policy it was meant to be for participating countries. That might or might not include the U.K. as a direct participant, depending on the outcome of Brexit negotiations. The British government’s preferred solution is to design a nationwide ETS  linked to the EU ETS, and it has pledged to implement a solution ‘at least as ambitious’ as the European carbon market. Looking ahead, the success of UK carbon pricing policy in accelerating the retirement of coal plants is a good indicator of the potential impact that the newly rebooted EU ETS can have going forward.

The inevitable decline of Australia’s coal generation

By Leonard Quong at Bloomberg NEF

Image via Bloomberg
Image via Bloomberg

Coal generation has long been the bedrock of Australia’s electricity supply, providing abundant, cheap baseload power to consumers. But the fleet is ageing and is faced with a series of economic battles for its long-term survival – battles the coal plants are unlikely to win.

Introduction

Age, and the effects of it, are at the heart of the problems facing Australian coal-fired generators. With an average age of 29 years, compared to a design life of between 40 and 50 years, Australia’s coal fleet is ageing. By 2050, nearly all of the country’s 25GW of coal capacity operating today will reach the end of their technical life, with almost 50% reaching this point between 2030 and 2040. Since 2016, already 2.8GW of coal capacity has retired due to old age or after encountering market conditions they were not designed to operate in.

Figure 1. Australian coal capacity with closure at end of technical life (Source: BloombergNEF)

With demand for electricity expected to continue growing, any gap in electricity supply left by retiring coal projects has to be filled. The rapidly changing economics of generation, and needs within the system, will determine Australia’s future generation mix.

Coal unlikely to fill supply gap

There are three main ways to fill the inevitable gap in supply left by retiring coal: i) build new coal plants, ii) life-extend the existing plants as they age, or iii) build something else.

Building new coal

Despite an abundance of coal reserves in Australia, building a new coal-fired power station is one of the most expensive forms of electricity generation. The market views building new coal as an extremely risky prospect. As a result, investors and debt providers demand a significantly higher rate of return for investments in coal projects. The three main risks are:

  • Carbon risk: Since the repeal of the Carbon Tax in 2014, Australia has lacked any long-term, robust, national decarbonization policy. Investors worry that any future policy or decarbonization mechanism will strand investments in new coal.
  • Market risk: The volatile nature of Australia’s electricity markets leaves coal generators particularly exposed to rapidly fluctuating electricity prices, changes in demand dynamics, and fuel prices increasingly linked with international commodity markets. 
  • Risk to reputation: Many Australia-based companies are reluctant to support any green-field coal plants due to increasing environmental, social and governance exemplarity expectations (and at times demands) from consumers, investors and shareholders. Already, most large domestic banks have ruled out financing any new coal projects in the country.

Due to these factors, there is very little appetite for any new coal generation projects within Australia’s investment community. Prospective developers struggle to de-risk projects and maintain a viable business model over the life of the project without relying on generous government support schemes (where none yet exist).

Life-extending coal

Extending the lifespan of a coal plant refers to investing new capital into an existing project to keep it operating beyond its initial end-of-life. Each plant will require different investments to continue operating, but even so the ability to life-extend Australia’s coal fleet is limited. Two asset owners, AGL Energy and Origin Energy, have already committed to closing down the coal plants they own at the end of their life – ruling out extending any of these projects. While this might not sound too significant, between the two them, these companies own 39% (10GW) of Australia’s existing coal capacity. 

About 8GW of the existing fleet would face severe economic barriers to having their operation extended, according to our analysis. These barriers include poor plant conditions, limited access to fuel supply, limited waste disposal options, or simply an inability to extend environmental permits. The poor condition of the coal fleet is also causing plants to trip, a technical failure that is more likely to happen during episodes of extreme heat that are increasingly frequent. For example, on January 18, 2018, the 500MW Loy Yang B plant, Australia’s youngest lignite power station, tripped whilst supplying around 6% of the state of Victoria’s power demand. The gap in supply was successfully compensated for by the system but these episodes are challenging the portrayal of coal plants as the most, or even only, reliable source of electricity by supporters of the sector in Australian politics.       

Taking into account company commitments and poor life-extension economics, only 7GW of coal projects operating today stand to be life-extended. Even if each of the projects that have any reasonable potential for a 15-year extension got one, there would still be a significant gap in supply left by retiring coal (Figure 2).

Figure 2. Australian coal capacity with closure at end of technical life with possible life extensions (Source: BloombergNEF)

Australian coal capacity with closure at end of technical life with possible life extensions. Source: Bloomberg NEF

Build something else

A mix of renewables, along with other flexible technologies, will be the most likely source of new generation in the market as coal projects retire. For years now, building new renewable generation has been the cheapest source of new electricity supply in Australia. Currently new large-scale wind or solar generation costs around A$55-90/WMh to build in Australia, with future costs expected to continue to decline.

Figure 3. Levelized cost of generation (Source: BloombergNEF)

Levelized cost of generation. Source: Bloomberg NEF

Operating coal is cheap, but building new coal is one of the most expensive sources of new generation, at around A$190/MWh, taking into the cost of capital expected by investors. The cost of life-extending coal projects is more uncertain, with each project requiring a different amount of re-investment to continue operating. Our analysis suggests that projects reasonably placed to life-extend could do so for around A$81/MWh.

When coal plants retire, there will be no perfect solution to plug any gaps in supply. The market will have to rely on price signals and perceived risks to determine the optimum mix of higher usage of existing assets, building new low cost generation, and flexible capacity.

More renewables require more flexibility

Most of the thermal plants operating today were built at a time, and with a budget, that did not value flexibility in coal generation. As these coal plants approach the end of their technical lives, what flexibility they had often decreases. Newer coal generation technologies have improved flexibility to some extent, but the rapid influx of renewables is challenging coal generation on two new fronts:

  • Demand following: Physically and thermally, large coal generators struggle to ramp their electricity output quickly. Historically, more expensive gas or liquid fueled ‘peaker’ plants were used to balance fast changes in electricity demand. However, as more variable renewable energy generators enter the market, the complexity of this challenge grows. Coal’s inability to ramp quickly means it is unlikely to be rewarded for the much more difficult task of balancing variable demand against increasing amounts of variable supply. 
  • Price following: At high levels of penetration, renewable energy generators suppress wholesale prices when they are operating, particularly in the middle of the day when small- and large-scale solar capacity is at full production. Older, inflexible coal power plants are unable to turn off during these periods, without remaining off during higher morning or evening price events, meaning that coal plants could be frequently exposed to very low or even negative prices.

In the nearly 10 years since the last new coal plant was commissioned in Australia, the country has installed around 6.3GW of solar on its rooftops and what will soon to be 11GW of large-scale renewable projects on the grid. With the amount of variable renewable generation in the energy mix expected to grow, it’s likely many coal plant owners will find themselves faced with a challenging economic situation before their technical end of life.

Companies reduce exposure to coal as climate risks increase

By Bryony Collins at Bloomberg NEF

Image via Bloomberg
Image via Bloomberg

From insurers to royalty-holding companies, investing in coal is becoming a riskier venture. Stricter regulation on coal imports in China and carbon emissions is making holders of these assets start to question the lifetime and long-term potential for the industry in a world where environmental protection is becoming more center stage.

Coal plant economics are also shifting. In many major markets including Germany, India, the U.S. and China, solar and wind energy plants are already cheaper than building new large-scale coal and gas plants, according to BloombergNEF’s New Energy Outlook 2018. And by 2030, the economic “tipping point” will occur almost everywhere, the report says.

Technology improvement and cost reduction in batteries will mean that intermittent wind and solar plants will increasingly be able to run when natural resources are lacking, which will eat into the most valuable operating hours for fossil fuel plants including coal, according to BloombergNEF. The research group expects some 1,290 gigawatts of new batteries to come online globally between now and 2050.

Added to this, the price of allowances on the European Union carbon market have doubled in the past year and they are now trading at around 20 euros per metric ton. This places a higher cost on emitters of CO2 in the bloc and creates further associated risk for insurers and investors.

Figure 1. EUAs double in past year (Source: Bloomberg Terminal)

EUAs double in past year. Source: Bloomberg Terminal

The prospect of worsening economics for coal does not bode well for investors, and many are reducing their exposure to the commodity. 

Coal royalties

Five years ago, coking coal accounted for all the income of Anglo Pacific Group, compared to just 42% of the company’s income now, Julian Treger, chief executive of the London-based natural resource investor, told BloombergNEF in an interview. The company has been diversifying into commodities like vanadium, nickel, cobalt and copper in line with a clean energy future, he said. 

Anglo Pacific will continue to reduce its exposure to coal, and in particular to coal with high ash content that is very polluting. “Those types of coal are becoming less valued and are proving to be poor investments,” in comparison to “high quality, less polluting coal, which the world seems to be valuing more” and is currently “extremely lucrative”, said Treger.

Monthly contracts for coal at the Newcastle coal terminal in Australia are currently trading at five-year highs, while the price of coking coal is at a ten-year high in China, said Treger. High temperatures over summer 2018 in China and other Asian countries boosted air conditioning demand and led to a growth in demand for power. A “lack of investment for new coal production has meant that existing coal mines are enjoying a windfall,” he said. Around four-fifths of Anglo Pacific’s coal investments are in coking coal for steel production, and one fifth in thermal coal for power generation, he said.

Anglo Pacific holds royalties in the Kestral coal mine in Australia that sells premium coal to China for prices that are 50% higher than typical on the market, said Treger. It is important that Anglo Pacific invests in coal that exceeds the specifications of the Chinese market, he said. Both Australian mines where Anglo Pacific has invested plan to expand significantly because the owners see growing demand for premium coal in Southeast Asia, he said.

Anglo Pacific sees exposure to coal declining naturally over time, due to mine depletion, even without diversifying into other commodities. Taxation on carbon emissions is also discouraging the use of less efficient coal, said Treger.

Glencore Plc expects investment in more than 107 gigawatts of coal plants, equivalent to more than 220 new coal-fired units over the next 15 years, in markets dependent on seaborne-traded thermal coal. Global energy demand from markets seeking low-cost power supply will continue to support the company’s coal mining business and fully utilize coal reserves, according to Glencore’s 2017 climate change report. However, on February 20th 2019 Glencore announced that it would limit coal production to current levels of about 150 million tons per year, in response to pressure from shareholders to improve its environmental performance. The company will focus new investment on mining commodities that support the clean energy and transportation future. 

Insurance

European insurers in particular are moving away from insuring coal projects and the companies behind them. Since 2015, some 17 major insurance companies have divested from coal, withdrawing an estimated $30 billion from the sector, according to the Unfriend Coal campaign. 

More than 100 financial institutions globally have introduced policies to restrict funding for coal, according to the Institute for Energy Economics and Financial Analysis. Since 2013, coal exit announcements have occurred at a rate exceeding one per month from banks and insurers with over $10 billion of assets under management, according to a reportfrom the institute. 

In a recent announcement from a bank, BNP Paribas plans to divest from companies deriving more than 10 percent of revenue from coal and to implement carbon intensity limits on power generators. 

In May 2018, Allianz announced that it would no longer provide standalone insurance for coal plants or coal mines, and that it would ban all companies planning to build more than 500 megawatts of new coal capacity from its investment portfolio. And other insurers have joined suite, including AXA and Swiss RE, as the damaging environmental effect of burning coal for energy becomes increasingly perceived as an unsustainable investment.  

However, U.S. companies AIG, Liberty Mutual, Chubb and Berkshire Hathaway continue to insure coal projects around the world, which demonstrates that the divestment movement has some way to go. AIG declined to comment on coal investment for this research.

The 40 largest U.S. insurers hold more than $450 billion in coal, oil, gas and electric utility stocks and bonds, according to Insure Our Future, a campaign against U.S. companies insuring and investing in coal and tar sands projects. U.S. insurers continue to financially prop up the coal industry, despite paying out in claims as a result of extreme weather events exacerbated by a changing climate. Wildfires in Northern California generated $12.6 billion in insurance claims in 2017, and that year’s hurricane season accounted for more than $200 billion in damages, according to an announcement from the campaign in September.

Insurance companies are starting to factor in the potential impact of climate change when making underwriting and investment decisions, but there is a lack of transparency as to how this applies to coal investment among some.

The reinsurance market also has an important role to play in reducing financial backing from the coal industry. The withdrawal of the biggest reinsurance companies would “challenge the expansion of the coal sector and hasten its phase-out,” said a briefing from the Unfriend Coal campaign in September 2018. 

Swiss Re is the only reinsurer to take significant action on coal, having announced in July that it will no longer provide cover to companies or projects which rely on coal for more than 30% of their revenue or more than 30% of the power they generate. Munich Re has also announced a new policy regarding insuring business in coal, but it is unclear how far this approach would extend to industrialized countries that account for less than 8% of new coal capacity planned or under construction, states the Unfriend Coal campaign. Divestment efforts often exclude a particular region, or only apply to companies with investment over a certain amount, so the case for outlying coal is a complex endeavor.

The more reinsurance companies join the divestment effort, the more difficult it will become for companies to continue to derive significant revenue from burning coal. The controversial Ostroleka C coal plant in Poland, which has a capacity of 1 gigawatt, is a case in point. The plant would operate from 2023 to 2063 – far beyond the timeline for phasing out coal in line with the Paris agreement – but it will require insurance in order to operate, and an underwriter prepared to take on board the associated potential risks. 

Poland has pledged to the EU that the Ostroleka project will be the last coal plant that it builds in order to meet the bloc’s carbon reduction commitments. In December, project owner Energa and Enea were awarded 15 years of subsidies in a capacity auction to build Ostroleka. The energy ministry viewed the project as important for power supply security and the need to synchronize the Polish power grid with the Baltic States. Winning the subsidies was necessary for the project to proceed to investment, the owners said. However, obtaining bank loans to fund the project may prove difficult as financial institutions scale down their support for coal investments, said Krzysztof Tchorzewski, Poland’s energy minister, cited in a Bloomberg News article.

Xcel energy’s push to decarbonize

By Colleen Regan at Bloomberg NEF

Image via Bloomberg
Image via Bloomberg

Xcel Energy, a large energy company with utilities stretching across the U.S. Midwest, is accelerating its transition to clean energy. After relying heavily on coal, natural gas and nuclear for most of its history, Xcel has made a recent push to decarbonize, leveraging its territories’ strong winds and solar irradiance levels. Its strategy aims to reduce greenhouse gas emissions by 60% from 2005 levels by 2030 and 100% by 2050, retiring multiple gigawatts of coal-fired power in the process.

Once one of the largest owners and operators of coal-fired power plants in the United States, Xcel has firmly pivoted toward renewable energy. Its current CEO, Ben Fowke, has noted that “it's not a matter of if we're going to retire our coal fleet in this nation, it's just a matter of when.” (Bloomberg News, “Coal Plants Keep Shutting Despite Trump’s Order to Rescue Them”, June 18, 2018.) Its self-described “steel for fuel” strategy seeks to displace these aging coal-fired units with a portfolio of low-cost wind and solar, complemented by flexible natural gas and batteries. 

Since 2005, Xcel’s carbon footprint has shrunk 35%, putting it well on the path to hit its 2030 target of a 60% decline. By 2022, it expects coal and natural gas – which made up 79% of its mix in 2005 – will represent only 39% of generation. Wind energy will be the primary source that displaces these fossil assets, generating 40% of Xcel’s power.

Figure 1. Xcel generation portfolio in 2005, 2017 and 2022 (expected). (Source: Xcel Corporate Responsibility Report)

Xcel generation portfolio in 2005, 2017 and 2022 (expected), Source: Xcel Corporate Responsibility Report

State policy was the primary impetus for Xcel’s move into renewable energy: for example, Minnesota’s renewable portfolio standard requires Xcel to source 30% of its retail sales from renewable energy by 2020, including a 1.5% carve-out for solar. A similar target in Colorado pushes for 27% renewables, plus a 3% target for distributed generation, by the same year.

But state policy drivers have slowly given way to economic stimuli. Xcel’s four regulated utilities cover some of the country’s best wind resources, straddling the blustery Great Plains, as well as robust solar resources in Colorado, Texas and New Mexico. 

Falling technology costs and federal tax credits, together with these strong resources, have allowed Xcel’s request for proposals (RFPs) for new wind farms to fetch prices under $22/MWh in its Northern States Power (NSP-System) territory, which includes its two utilities in Minnesota and Wisconsin. Even better, its Southwestern Public Service Co. in Texas and New Mexico secured new wind bids at $19/MWh. These wind prices are very attractive: in both NSP-System and Southwestern Public Service territories, they undercut the operating costs of Xcel’s coal-fired units, while in Colorado, recent wind prices have been competitive with its coal-fired fleet.

Figure 2. Operating costs of Xcel’s coal units versus announced wind PPA price or LCOEs. (Source: Xcel, Bloomberg NEF)

Operating costs of Xcel’s coal units versus announced wind PPA price or LCOEs. Source: Xcel, Bloomberg NEF

Already the largest producer of wind generation among the country’s electric utilities, Xcel plans to build – and own – at least an additional 3.6GW of wind capacity. Its various utilities commissions have approved these plans, meaning that Xcel will earn a return on these capital expenditures of about 9.5-10%. The ability to earn returns on renewable energy investment (as opposed to merely passing along costs, as Xcel does when it signs a power purchase agreement for renewable energy – meaning someone else earns a return) is another key driver for Xcel in ramping up its renewable energy build.

In Colorado, its utility proposed – and received approval from the public utilities commission in August 2018 – to close the 660MW Comanche coal power plant from 2022-25, a decade earlier than planned. Xcel will instead invest $2.5 billion across 1,100MW of wind, 700MW of solar and 275MW of battery energy storage; along the way, it expects to save customers $213 million. Retiring the coal plants is a key part of Xcel’s cost-savings plan: fewer outlays on fuel will save on operating costs, and the transmission lines and interconnections left open by Comanche’s retirement will reduce installation costs for renewables. Xcel expects these actions to reduce its Colorado emissions by 60% below 2005 levels by 2026, four years early, at no incremental cost to customers. At the same time, it expects renewable energy generation will rise to 55% of its portfolio.

The shift away from coal by U.S. utilities is due to a confluence of factors, including competition from low-priced natural gas and renewables, aging boilers, and increasingly effective opposition from the local communities impacted by coal plant pollution. As a result, coal provided only 30% of electricity in 2017. This figure contrasts with its 49% share 10 years earlier in 2007 and represents the lowest share held by coal in at least the past 70 years.

Coal will play minor role in expanding access to energy

By Itamar Orlandi, CFA at Bloomberg NEF

Solar power in Indonesia
Solar power in Indonesia

More than 230 million homes, mostly in Africa and South Asia, will receive electricity for the first time ever between now and 2030. Copper and silicon will be the enabling commodities in this endeavor, not the coal and oil that helped bring power to the first six billion consumers globally.

Transmission and distribution networks will draw most energy access investments

The effort will require some $162 billion in capital investments, according to BloombergNEF estimates. Improvements to the electrical grid will account for more than half of the investment to boost electricity access in developing countries (Figure 1). A large proportion of those without electricity, particularly in Africa, are located fairly close to existing infrastructure, sometimes almost under existing transmission and distribution lines. Some 161 million city dwellers were not served by electrical utilities in 2016. Reaching those often requires very short extensions to the grid, or even just formalizing pirated connections. 

Figure 1 : Projected electricity access investments 2018 - 30

Source: BloombergNEF

Expanding the grid is much harder in remote areas, where an agrarian population is often highly dispersed. There, a new connection can cost hundreds of dollars per household, and in extremely difficult areas such as the Peruvian Andes even more than $2,000. Making these costly connections financially viable would require hefty margins on the power sold. The problem is that most households in remote areas are poor and consume tiny amounts of electricity. BNEF estimates that a set of typical basic appliances such as lights, fans, a refrigerator, a TV and phone chargers would consume only between 72 -783kWh per household annually, depending on the appliance mix. The utility bill for such low consumption would amount to just a few dollars per year, far too little to pay back the investment in the distribution grid.  

With ever more energy-efficient appliances, from LED lights to fans and refrigerators, that power consumption could end up being even lower unless rural areas see a sudden and unexpected level of economic growth. BNEF estimates that serving the entire population currently disconnected from the grid for a year would only require 111 terawatt hours, about as much as the annual electricity consumption of the Netherlands. Assuming that most rural households are not able to afford relatively costly and power-hungry appliances such as refrigerators, that figure drops to just 31 terawatt hours, roughly the same as Ireland’s annual power demand. Unlike in those small countries, this demand is distributed over vast regions of Africa, South Asia and archipelagos in the Pacific. 

Figure 2 : The energy needs of one billion people without electricity access compared with countries

Source: BloombergNEF

This combination of limited power demand and large geographic distribution puts large coal power plants at a disadvantage relative to technologies such as solar, battery storage and diesel generators, which can be installed in smaller units closer to where the energy is needed. 

Microgrids and solar home systems beat centralized power plants on distribution costs

Small-scale solar installations bundled with batteries are a more expensive way to generate electricity than large, centralized power plants. But in order to reach far-flung areas, the cost of generation and distribution has to be considered together. Adding the amortization cost of a grid extension over twenty years can double the retail tariffs that developing country utilities charge clients, bringing the total up to $1/kWh. Microgrids and solar home systems bundled with super-efficient appliances optimized for use with a solar modules can compete at those rates (Figure 3). Together, we project these solar-centered approaches will start to bring power to more households than the grid from the middle of the 2020s, reaching a total of 106 million homes by 2030. Managing and maintaining such distributed systems will require digital technologies to remotely monitor payments and diagnose malfunctions. 

Figure 3: Cost of delivered energy for low income consumers (207kWh per year) and cost of delivered energy for medium income consumers (985kWh per year)

PPCA-access-Fig 3 and 4.JPG

Source: BloombergNEF

Note: low-income customers are assumed to use 207kWh per year or a 10-35W solar home system. Medium income refers to a consumption of 985kWh/year and a 200W solar home system. The microgrid with daytime load produces additional electricity for non-residential activities. 

Barely any new power plants are needed to reach everyone

The existing power generation capacity even in many developing countries would not need to be radically expanded even if the connected population multiplies. Most of today’s power demand in those nations comes from industry and wealthier urbanites. Generating the 38 terawatt hours per year that we project will be needed to serve the 133 million homes that will be connected to the main grid by 2030 would require just about 5-6GW of new coal-fired power plants. That is just a handful of power plants. 

Boosting energy access is a distribution problem, not a generation problem

The limited need for new power plants highlights that boosting energy access is really about reaching new populations, not building new power plants. Countries that have rapidly improved their electrification rates in recent years, such as Kenya and Rwanda, have done so by promoting off-grid solar programs or new utility connections, not new power plants. The latter will undoubtedly be required to boost the local industrial base. But the economics of reaching the poorest favor small energy resources that can be installed close to where they are needed. 

Chile’s new coal fleet challenged by renewables and air pollution

By Natalia Castilhos Rypl at Bloomberg NEF

Image via Bloomberg
Image via Bloomberg

Chile has the most coal-dependent electricity mix in South America. Coal-fired generation, most of which came online over the last decade, has helped fuel one of the region’s most dynamic economies and its energy-intensive industries, such as a copper sector that now accounts for a third of all power consumption.

Powering considerable economic growth

Chile’s economy has grown more than 50% over the last decade and the country now has the highest GDP per capita of the continent. New coal plants have met most of the added electricity demand over the period. Coal’s installed capacity has doubled since 2010 and currently provides 22% of the total capacity. In a given year, Chile’s 5GW of coal plants produces about 40% of the country’s total electricity generation.  

Figure 1. Chile net capacity additions per technology and GDP

Chile net capacity additions per technology and GDP. Source: CNE and Bloomberg NEF

(Source: CNE and BloombergNEF)

Figure 2. Chile net capacity additions per technology and GDP

Chile net capacity additions per technology and generation. Source: CNE and Bloomberg NEF

(Source: CNE and BloombergNEF)

However, the Chilean government also saw the importance of developing renewables to mitigate the increasing emissions intensity of the country’s generation. The country’s exceptional solar and wind resources, combined with the drop in the cost of renewable energy technologies, confirmed the government in its position. The country has one of the region’s most sophisticated power sector regulatory environments, which enabled it to develop its renewables support. Private companies are active across power generation, transmission and retail. Electricity trades on a wholesale power exchange with nodes indicating the value of electricity in different locations. Frequent tenders for long-term power purchase contracts, with a design that favours renewables, successfully transform the interest of developers into large investment volumes. 

In 2013, the government introduced a series of regulations to support renewables that resulted in the addition of 3.7GW of renewables capacity. All utilities with more than 200MW of generation capacity, under Law No. 20.527, must ensure 20% of that is renewables by 2025, twice the earlier target. A carbon tax set at $5 per ton of CO2 emissions for power generators was also introduced in 2014. The first annual tax receipt covering 2017 emissions stood at $191 million, 94% of which paid by power generators using fossil fuels. However, the effect of the tax on the power sector was somewhat blunted through two clauses. Firstly, the carbon tax is not taken into account in determining dispatch, preserving the position of coal generators in the merit order. Secondly, coal generators are compensated whenever the cost of the tax is higher than their marginal cost which resulted in an around 15% discount in payments for the year 2017. Whilst Chile’s carbon tax is one of the first in the region, it fails to significantly impact the place of coal in the power mix under its current framework. 

The government completed these measures in 2014 with a reform of Chile’s technology-neutral electricity procurement auctions. These have become renowned for record low bids from clean energy generators that outcompeted fossil fuels. The new rules divided the auctions into time blocks, with generators competing to deliver electricity over that time window alone in a PPA awarded for 20 years. This was particularly successful in ensuring the maximization of solar development as the technology beats any other for delivering daytime electricity thanks to the country’s exceptional solar resources. However, the considerable improvement in economics for onshore wind have also meant renewables have also won most of the contracts on offer outside of the time blocks that favour solar. In two of the past three auctions, companies bidding with renewables portfolios were the only ones to win contracts. Chile has recorded $10 billion of clean energy investment since 2013.

Figure 3. Auction results by size, price and share of renewable winners

Auction results by size, price and share of renewable winners. Source: CNE, Bloomberg NEF

(Source: CNE, BloombergNEF)

Chile’s elongated power markets

The surging growth of renewables, combined with Chile’s sophisticated and regionally differentiated wholesale power market, have highlighted the integration challenges of an ambitious energy transition. The share of renewables in Chile’s electricity generation jumped to 24% in 2018, from 9% just six years earlier, as a result of the government’s effective policy mix.

Chile’s power grid used to be divided into four main systems, with little or no interconnection between them. In the north, the Sistema Interconectado Central (SIC) and Sistema Interconectado del Norte Grande (SING) subsystems have to meet most of the country’s energy demand. The SIC serves 90% of the population, whilst SING has a high concentration of industrial activity, in particular mining.

Figure 4. 2017’s installed capacity, generation and coal assets

Source: Chilean Ministry of Energy, CNE, Bloomberg NEF. Note: there are 27 coal plants concentrated in six locations above illustrated

(Source: Chilean Ministry of Energy, CNE, BloombergNEF. Note: there are 27 coal units concentrated in the six locations above illustrated)

The north of the country covered by the SING system is where the Atacama Desert is located. It receives some of the strongest, most consistent sunshine on Earth. The Cerro Dominador concentrated solar power project, Latin America’s first, is being built in the Atacama Desert. It will allow for stored heat to be used for power generation at night. However, the vast majority of renewables development to date has happened in the SIC, closer to residential and commercial demand centers, with 93% of all wind and 70% of solar projects commissioned in the area. 

There is lack of transmission capacity, in particular interconnecting the four systems. This has rapidly led to the curtailment of renewables generation, which reached 16% of renewables generation in 2017. A first major step toward improving the situation was made in November 2017, when the 600-km transmission line that connects the SING and SIC was commissioned. The $880 million investment has helped reduce curtailment, but Chile is investing considerably more in the expansion of its grid. A second interconnection between the two largest systems is due to be commissioned in 1Q 2019, and the government launched a grid expansion tender program in 2017 that will require around $2 billion of investments for the development of more new lines.

Chile’s path to decarbonization and the outlook for coal

In response to the surge in renewables development, the share of fossil fuels in the generation mix fell from 66% to 54%, with oil and diesel dropping the most. Coal contributed 37% in 2017, below the 46% peak of 2013. This lower share, however, is a result of better availability of hydro generation. The share of coal is expected to increase once again in 2018 as less rainfall was recorded. With much of the coal capacity only just commissioned, BNEF expects policy intervention will be needed to significantly reduce the role of coal in the generation mix in the short to medium term, and the government seems prepared to deliver it.

In 2016, Chile released its long-term energy plan, which sets a target for renewables to account for 70% of electricity by 2050. In January of 2018, AES Gener, Colbún, Enel and Engie, the four companies that own Chile’s coal assets, made a voluntary agreement with the government committing to not invest in new coal projects that do not integrate carbon capture and storage systems. The agreement also stipulates that the four companies will work toward the decarbonization of their existing assets along with the government. At first, a series of round-tables bringing together the various stakeholders of Chile’s power sector has been held throughout 2018 to develop criteria that should inform the coal phase out challenge, including consideration of transmission constraints and the potential of various technologies to replace coal. The government’s current plan is that the four utility companies with coal power plants will then voluntarily propose their own coal phase out pathways, which will then be aggregated and analysed. A schedule for the retirement or conversion of Chile’s coal plants is due in 1Q 2019, with the target year likely to fall between 2030 and 2040. 

A preliminary study on the future of the Chilean grid without coal concludes that an extra 5GW of capacity would have to be deployed by 2040 compared to a scenario where no new coal capacity is added and existing plants are retired at the end of their lifetime. The mix of technologies would lean towards gas over the coming decade, before a mix of solar, wind, pumped hydro and batteries take over. This transformation would require more investment into new generation and grid assets. 

The signal from the Chilean government that it is serious about finding a way out for unabated coal, combined with efforts to mobilize record investment into clean energy and the grid, has set the country on the path of a coal phase-out at a pace that was unimaginable some years ago. Shortly after the announcement of the decarbonization plan, Engie (a member of the Powering Past Coal Alliance), requested an authorization to retire two coal units totalling 170MW of capacity located at Tocopilla, as they have become uneconomical due to their age. The plants are going to be decommissioned as soon as the transmission line Cardones-Polpaico becomes operational, which will increase the flexibility of the Chilean grid and allow renewable generation to better flow within the country. In parallel, Engie is soon going to commission the last coal power plant in the country, a 375MW plant located at Mejillones. 

Air pollution is also playing a critical role in driving Chile’s coal plant decommissioning objectives. The country’s old coal plants in particular have been responsible for regional air pollution. In August 2018, the regions of Quintero and Puchuncaví suffered a major environmental crisis as air pollution reached levels toxic to local communities. The government responded by forcing one coal unit at the AES Gener 884MW coal power plant to shut down temporarily. 

Integration with the energy systems of other countries in the region will additionally play an important role in delivering Chile’s decarbonization strategy. Chile’s neighbor, Argentina, has recently increased production of unconventional gas and started to export to Chile for the first time in 11 years. Chile’s minister of energy, Susana Jimenez, also plans to expand interconnection, especially with Argentina and Peru, to increase the flexibility of the grid. Currently, Chile has only one international electricity transmission line with Argentina, inaugurated in 2015.

Consensus across party lines points to continued ambition

Whilst there are ideological differences between Chile’s main political groups, the country’s dedication to mitigating climate change is solid. The current president, center-right leader Sebastian Piñera, took office in March 2018 and immediately confirmed the decarbonization policy of outgoing center-left President Michelle Bachelet. This will now be complemented through the development of a new climate change law.

The 2018-2022 energy agenda of the current administration set decarbonization as a top 10 priority. It has added a new law on energy efficiency; increased the capacity thresholds under which renewables generators can access the advantages granted to distributed generation; and set a goal of increasing EV penetration tenfold by 2022. 

Chile ranked 1st in BloombergNEF’s 2018 Climatescope report, a survey of the attractiveness of 103 emerging markets for clean energy investors. This was achieved thanks to the combination of ambitious renewables policies, power sector regulation that favour investors, and a track record of clean energy investments. The solutions that will allow Chile to maintain its standing as a hotspot for clean energy investment globally are also those that will allow the country to accelerate the phasing out of coal generation and meet its decarbonisation objectives. Expanding interconnections between Chile’s grid and introducing more sophisticated power market regulations will be critical in providing the grid flexibility and resilience needed to allow for higher levels of renewables penetration. 

Orsted’s profitable transformation from oil, gas and coal to renewables

By Tom Harries and Meredith Annex at Bloomberg NEF

A wind farm, under construction
A wind farm, under construction

Since 2010, Orsted has undergone a strategic and geographical change – stretching even to its name. Once known as Dong Energy – the ‘Danish Oil and Natural Gas’ company – it has successfully transformed itself into Orsted, a renewables-led utility. Offshore wind is the flag-bearer for its new identity, but biomass conversions and acquisitions also play a part. Not only has Orsted gone green, it has also seen increased earnings. Since its initial public offering in 2016, the firm’s market capitalization has outperformed its old oil and gas foes. Orsted now sits close to the top when compared to its new utility peers.

From oil and gas producer…

In 2010, nearly half the earnings of Orsted (then known as Dong Energy) came from exploration and production or thermal generation activities (In 2010, 49% of Orsted’s Ebitda was from exploration and production or from thermal generation activities. The rest was from other activities, especially sales, distribution and trading). Around 70% of its power plants burned coal, gas or oil (Figure1).

Figure1 : The evolution of Orsted’s power assets

Figure 1:	The evolution of Orsted’s power assets

(Source: BloombergNEF, Orsted. Notes: Based on company filings and M&A data from Bloomberg Terminal. Calculated using gross capacity. Includes capacity from LCE – Lincoln Clean Energy, and Deepwater Wind acquisitions.)

By the time of its name change, this share had reversed – over 70% of Orsted’s 2017 power fleet was renewable. And the evolution is far from over. By 2020, the share of its fleet burning fossil fuels is expected to reach a mere 10%. That means 90% will come from clean energy sources: biomass and waste burning plants and onshore and offshore wind farms. 

This transformation should see Orsted’s carbon emissions from power and heat fall sevenfold: from around 350gCO2/kWh in 2010 to around 50gCO2/kWh in 2020 (Taken from Orsted’s Capital Markets Day 2018 presentation. Excludes oil and gas). Plus, the firm has sold off its oil and gas production assets – making the drop in corporate emissions even starker.

…to offshore wind major

What made this possible was a pivot to renewables, and particularly to offshore wind. In fact, the firm is now Europe’s leading offshore wind developer. 

Orsted is on course to have developed just under eight gigawatts of offshore wind capacity in 2020 – an eightfold increase from where it was in 2010. And this market-leading position is unlikely to change anytime soon. Already, the firm has an existing and planned offshore wind project pipeline in Europe that is more than double the size of the second-most prodigious developer: Vattenfall.

Figure 2: Top 10 offshore wind developers in Europe

Figure 2:	Top 10 offshore wind developers in Europe

(Source: BloombergNEF. GIP – Global Infrastructure Partners. BloombergNEF’s offshore wind developer ranking tracks a developer’s net capacity, pro-rata to the developer’s equity share of commissioned, financed and active pipeline projects in Europe.)

While most offshore wind activity is located in Europe, Orsted is also active internationally.

It is an early entrant in Taiwan, where it has lined up 1.9 gigawatts of capacity as the country looks to replace a retiring nuclear fleet with renewables and gas. 

Orsted has also entered the US initially by replicating its European strategy of acquiring sites for offshore wind farms. But in November, it changed tack and acquired one of its key US rivals: Deepwater Wind. The acquisition includes the only operating offshore wind farm in the US, as well as a number of projects that have secured long-term offtake agreements and several new sites. As a result, Orsted is now in a more competitive position in upcoming offshore wind auctions across the Eastern seaboard.

All in all, this makes Orsted not just the largest offshore wind player in Europe – but also a leader globally.

Underpinning it all: a transforming strategy

This chain of events was started with a new strategy released in 2013. The plan, released in February of that year, established that by 2020 Orsted would divest non-core assets and invest its earnings from upstream oil and gas into offshore wind and biomass. 

Five years later, it is on course to meet its renewables goals. In addition to the eight gigawatts of offshore wind that BloombergNEF expects Orsted to commission by 2020 (exceeding its target of 6.5 gigawatts), the firm has divested onshore wind and hydro assets (Figure 1) and is on track to have either divested or converted most of its coal and gas power plants to biomass by 2020. 

Of course, not all has gone to plan. Orsted has renegaded on its onshore wind plans: after selling off assets, it has re-entered the industry in the US with its acquisition of Lincoln Clean Energy in 2018 – which primarily develops onshore wind and solar. It also didn’t keep to its initial intentions around oil and gas. Orsted started to raise cash by selling shares in its offshore wind farms to institutional investors, such as pension funds. This meant the firm did not need to rely on exploration and production activities to fund new business. So, in 2017 it sold its upstream oil and gas business, transforming Orsted from a fossil fuel company to a renewable energy firm. 

The change has been cemented in a name: once called Dong Energy (Danish Oil and Natural Gas), the firm is now branded Orsted in honor of a Danish scientist who discovered that electric currents make magnetic fields.

Renewables driving earnings at no expense to company value

The transformation is clear in Orsted’s earnings. Thermal generation and oil activities (exploration and production) accounted for well over half of Orsted’s Ebitda before 2010. Yet earnings from its wind development business have been rising steadily. In 2017, wind accounted for 91% of Orsted’s total Ebitda while fossil fuel-based activities – from generation or from exploration and production – were a mere 1% of total earnings. 

Figure 3 : Orsted Ebitda by business segment

(Source: Bloomberg LP, BloombergNEF.)

Note: Depicts unadjusted Ebitda. Wind power was only separately reported starting in 2010. The lower performance in 2012 was largely due to Orsted’s “customers and market” business unit.

What’s more, Orsted’s transformation seems to have paid off in terms of company value. Orsted’s market capitalization – or “market cap” – captures the total value of the company’s stock currently held by shareholders; Orsted’s has risen 64% since its IPO in 2016. This is greater than the gains seen by the six largest independent oil companies in Europe, which essentially makes up Orsted’s pre-transformation peer group. 

Now, in its current form, Orsted more closely resembles a utility – and even here the firm fares well. Orsted currently tops the list of largest utilities in Western Europe by market cap, according to Bloomberg equity data. Of the largest European utilities, only EDF has seen its market cap grow more than Orsted’s since the IPO – while others in the region have seen their market cap fall or barely change.

Figure 4: Change in market capitalization since Orsted IPO, compared to peers

(Source: Bloomberg LP, Bloomberg NEF.)

Note: Shows change in market capitalization from June 9, 2016, to November 1, 2018. Negative value indicates that market capitalization has fallen over this time period. Naturgy was formerly known as Gas Natural.

Under pressure: coal economics overtaken by solar and wind

By Matthias Kimmel at Bloomberg NEF

Image via Bloomberg
Image via Bloomberg

Coal is the most important fuel in electricity generation today, accounting for 38% of global power production. Its use, however, is set to peak in 2027 and slide thereafter. The contribution of coal might drop to just 11% by 2050, as low-cost renewables, more flexible gas and cheap batteries push in and reshape the electricity system. Decreases in coal generation in almost all countries, including in large economies that are heavily reliant on coal today, will drive the global decline of the fossil fuel. 

The fundamental change of the role of coal in the power system is one of the key findings of BloombergNEF’s long-term outlook for the future of electricity, the New Energy Outlook 2018. The report aims to find answers on what the cheapest power system in the future might look like, analyzing the competitiveness of energy technologies and their ability to meet electricity demand. The analysis draws its conclusions without factoring in aspirational government targets that may accelerate the transition, such as coal phase-outs, and subsidies that might favor renewables over fossil fuels.

Coal loses the cost race against solar and wind

The quickly falling costs of solar and onshore wind, and the limited capability of coal power plants to operate flexibly alongside variable renewables, herald the decline of coal power. In North America, Europe, India, Brazil and Australia electricity from new, unsubsidized wind and solar photovoltaic power plants is already cheaper than new coal. In China, where coal represented 40% of capacity additions between 2015 and 2017, the costs of recent solar photovoltaic projects are now on par with those of new-build coal and will start to undercut them from 2019. In most of Southeast Asia, this happens by 2022, and by 2025 it happens in Japan.

Prospects are dim for coal to match solar and wind’s cost cuts achieved from better manufacturing, economies of scale and improving efficiency. In many economies, capital costs of new coal power plants have increased with the introduction of more complex technology to limit air pollution. At the same time, improvements in minimizing energy losses in coal-based electricity generation are slowing. This is because gains in efficiency of steam turbines – the machines that convert the thermal energy of coal into mechanical energy – are ever harder to achieve as the technology further matures.

Figure 1. When solar and wind become cheaper than new coal power plants

(Source: BloombergNEF)

Because of coal’s worsening cost competitiveness against solar photovoltaics and wind, new coal build is set to drop in all markets. Around 355GW of new coal plants, equivalent to $190 billion of investments, still get commissioned out to 2025. Many of these are legacy projects that were planned and financed many years ago, predominantly in China and India. Yet, by the middle of the next decade, annual additions of new coal power start to plunge. On average, the world adds less than 5GW of new coal per year between 2025 and 2050, compared with an average 78GW between 2015 and 2018. China, Europe, North America, Brazil, Australia and South Korea are among the regions that add zero coal after 2025. India continues to invest in the fuel until the early 2040s, mostly for system security reasons, adding about half of the global coal capacity, worth $45 billion, between 2026 and 2050.

Global installed coal capacity reaches its maximum at 2,107GW in 2022, before dropping by an average of 46GW per year out to 2050 as plant retirements exceed additions. By 2050, only 5% of all the power generating capacity installed worldwide runs on coal compared to almost a third today.

Figure 2. Global investments in coal by region, 2018-2050

(Source: BloombergNEF)

Generation and emissions peak in 2027

Coal generation peaks at 9,900TWh five years after capacity has reached its maximum, driven by a second cost dynamic: when it becomes cheaper to build a new onshore wind or a solar photovoltaic plant than to run an existing coal plant. Both China and the U.S. are critical in this regard. China will account for 51% of global coal generation that year, and the U.S. will have 6% – at which point solar and wind PV begin to undercut the operating costs of their existing coal power plants, squeezing coal’s run hours and accelerating the closure of old, inefficient generators. Between 2027 and 2040, global coal generation declines 2% each year on average, and 5% per year in the decade to 2050. By mid-century, coal generates only one in nine kilowatt-hours needed to meet demand.

As the share of variable renewables increases, the limited flexibility of coal power plants to quickly adjust their load to wind and solar output further aggravates the fossil fuel’s challenging position in a transformed power system. Batteries and so-called peaker gas generators help with the integration of renewables by providing flexibility to the power grid, and the primary purpose of coal shifts from providing bulk electricity around-the-clock to energy provision during nighttime hours and extreme periods of low generation and high demand not met by renewables. 

Power sector emissions go hand-in-hand with coal generation and also peak in 2027. Coal, gas and oil power plants emit around 13.6 gigatons of carbon dioxide in that year – an increase of 2% relative to 2017 levels. Coal emissions account to 10.5 gigatons in 2027. By 2050, power sector emissions decline to 8.5 gigatons, of which 4.7 gigatons are coal.

Despite an aggressive increase of renewables and concurrent decline of coal in this scenario, emissions are nonetheless far from limiting global warming to 2 degrees Celsius above pre-industrial levels. By 2050, cumulative emissions overshoot the power sector’s carbon budget 86% or 180 gigatons of carbon dioxide. For warming to stay below 1.5 degrees, the electricity sector would need to abate another 63 gigatons relative to the 2 degrees pathway – or 243 gigatons compared with a lowest-cost power system – becoming effectively carbon-neutral at around 2050. Thereafter, the Intergovernmental Panel on Climate Change (IPCC) suggests that the sector might even need to remove carbon from the air to avoid further warming.

Phasing out coal with policy means more gas, some more renewables

In a scenario where governments phase out coal worldwide between 2025 and 2035, both gas and renewables would see faster growth than in a power system optimized around meeting demand at least cost. Gas generation would increase and take up about 73% of the void, which in turn would require adding 51% more generation by 2050 than in the least-cost scenario. An extra 1,196GW of new gas plants would provide this electricity. An additional 715GW of solar and wind, aided by 531GW of additional utility-scale batteries, make up the rest of the gap left by coal – which is equivalent to 11% more generation than if coal was not phased out.

Eliminating coal and replacing it with a least-cost combination of renewables, batteries and gas pushes emissions down to 5.2 gigatons of carbon dioxide or 54% below the least-cost system trajectory in 2035. This is somewhat good news from a climate perspective, as this emissions level would bring the world close to a 2 degrees Celsius trajectory in the medium term. The gap to a 1.5 degrees Celsius would still be substantial, though, with emissions needing to be cut by another 43% just through 2035 and an extra 93% in the period to 2050. The IPCC projects that climate-related risks to health, livelihoods, food security, water supply, human security, and economic growth would increase significantly even if global warming reaches 1.5 degrees.

Simply getting rid of coal will not be enough to keep the earth on track for 2 or 1.5 degrees in the longer-term. For this, an earlier, faster and more aggressive abatement of emissions would be required. Policies that effectively cut emissions beyond just coal’s, ambitious energy saving and efficiency measures as well as new zero carbon technologies that can decarbonize gas at scale or supplant its role in the power system are some of the available options to achieve this goal.

Figure 3. Evolution of the global generation mix under a coal phase-out scenario

(Source: BloombergNEF)

This story is based on the New Energy Outlook 2018, BloombergNEF's long-term analysis of the evolution of the global power system. Updated annually, the report compiles, updates and forecasts data on costs, energy prices, capacity, generation and emissions. 

UK Government policy ushers coal towards retirement

By Andreas Gandolfo at Bloomberg NEF

Image via Bloomberg
Image via Bloomberg

Coal has played a major role in the UK's electricity supply over the past 20 years, generating around 30% of the country’s output in this period. The former state-owned Central Electricity Generating Board constructed most of the country’s modern coal fleet in the 1960s and 1970s, a portion of which remains operational in 2018. European policy set the first hurdle on the country’s coal fleet, with the Large Combustion Plant Directive (LCPD) leading to 8GW of shutdowns.

However, UK government policy over 2011-18 has created the conditions for the inevitable exit of coal from the country’s power mix. The mandated coal phase-out by 2025 sets a hard deadline on coal generation. Few plants will reach that date as the country’s carbon price floor has cast a long shadow on the economics of coal generators.

Figure 1. UK generation mix 

 

(Source: Department of Business, Energy, and Industrial Strategy, Bloomberg NEF. Note: Other fuels includes hydro and oil, renewables includes wind solar and biomass)

Figure 2. U.K. Coal capacity factors

(Source: Department of Business, Energy, and Industrial Strategy, Bloomberg NEF. Note: Other fuels includes hydro and oil, renewables includes wind solar and biomass)

Early clouds in coal's path

Coal’s position of dominance in the UK first came into question in 2001, when the EU passed the Large Combustion Plant Directive (LCPD). This capped various emissions for existing and new combustion fuel plants above 50MW in size. Non-compliant existing plants could either choose to upgrade their facilities to meet the targets, or opt out by limiting their run-hours and shutting down by 2015 at the latest. Around 8GW of capacity, 29% of the UK’s coal fleet when the directive was passed, decided to opt out and close by the designated date.

Almost a decade after the LCPD, the EU decided to tighten its emissions regulation with the Industrial Emissions Directive(IED). Similar in nature to the LCPD, the IED gave plants three options: comply; enter a so-called transitional national plan (TNP); or opt-out.

The IED did not result in the upheaval that the LCPD brought to UK coal. More than half of the UK’s remaining coal plants opted into the country’s TNP.

UK policy decides to tackle coal

European emissions policy did its fair share to shut down a significant portion of the UK's aging coal fleet. However, UK climate and energy policy turned out to have significantly sharper teeth. In a series of decisions over 2011-18, successive UK governments laid the ground for a coal-free future by as early as 2025. 

The UK capacity market

In late 2011, the then Department for Energy and Climate Change (DECC)(Now replaced by the Department for Business, Energy, and Industrial Strategy or BEIS), announced that as part of its Energy Market Reform (EMR), the UK was going to implement a capacity market.

At first glance, this policy tool does not appear to have much to do with coal’s possible demise. In fact, when DECC introduced it, many claimed that it would prolong coal’s operations in the UK However, when the economics of coal turned in late 2016 (see next section for more), they started failing to clear in the capacity market. Other projects, including many less carbon intensive new-builds and demand response, filled the gap left behind by coal plants.

As it turned out, this policy revealed that coal could be phased-out without risking energy security. By guaranteeing enough capacity in the system, the capacity market removed one of the coal industry’s main arguments in its favor, that it is essential to avoid blackouts. 

Carbon price floor

The next step in UK policy against coal was the introduction of a carbon price floor in April 2013. After years of low prices in the EU’s Emissions Trading Scheme, the UK decided to set a top-up on Emission Allowances (EUAs), pushing up total emissions costs for UK fossil fuel generators. (Read more on how the UK’s carbon price floor works). A high enough price for carbon increases the cost of electricity generated by emission intensive fuels, such as coal. In turn, this makes pricier yet cleaner alternatives relatively more attractive.

The scheme introduced a gradually increasing price below which UK carbon costs cannot go (In the 2017 Autumn Budget, the UK government froze the carbon price floor at "current levels"). Until 2015, it had little effect on the operations of coal plants, as it was too low to incentivize switching from coal to less carbon intensive gas generation. However, over 2015-16, the price floor increased by a staggering 66%. All of a sudden, coal plants were out of the money, with capacity factors plummeting from 40% to 20% in a matter of months. 

This development had the add-on effect of making coal plants increasingly uncompetitive in the capacity market, further worsening their already deteriorating economic position. Over 2016-17 an additional 6GW of coal shut down. Reduced run-hours, low revenue, and the prospect of having to invest in order to comply with the IED was behind their decision to shut down. 

2025 coal phase out

In late 2015, the UK government announced its intention that unabated coal should cease operations by 2025. Following the conclusion of consultation processes, in January 2018 the government presented its plan for implementing a coal phase-out by October 2025.

By the time the UK confirmed its policy intention, coal had already suffered a significant blow from the rise of the carbon price floor. Nonetheless, the few plants that saw a possible future in the UK are now forced to plan their closure no later than 2025, with most expecting to do so earlier.

Figure 3. Cumulative UK coal capacity by LCPD status 

(Source: Bloomberg NEF, Bloomberg Terminal. Note: Future UK coal capacity estimated based on closure announcements and capacity market results)

Figure 4. Cost of emitting a ton of CO2 for U.K. Generators 

 

(Source: Bloomberg NEF, Bloomberg Terminal. Note: Future UK coal capacity estimated based on closure announcements and capacity market results)

The outlook for UK coal

Despite being allowed to run until 2025, few remaining coal plants appear willing to do so. The doubling of the carbon price has harmed the economics of coal plants. That, in turn, has reduced the clearing rate for coal units in the UK capacity market. In the last T-4 auction, held in 2017, only 2.9GW of coal managed to clear – 25% of participating coal capacity. Even these last plants will struggle to get to 2025, despite having conformed to IED regulations. 

The suite of policies deployed by the UK government has been very effective in phasing out coal whilst ensuing energy security and promoting the use of lower emission generation. The carbon price floor ate into the profits of coal plants, making these old assets uneconomic. The capacity market quelled fears about what is going to replace them. Finally, the 2025 end date for unabated coal will guarantee that even those generators that manage to weather the storm will eventually close.

This coordinated policy is creating an important breathing space for two generator types:

  • Gas plants have increased their run-hours, improving their economics. This has been enough to keep existing plants online, but has not resulted in new gas build, as the outlook for all fossil fuel generation is negative.
  • Renewables are helped by the higher power prices that the carbon tax and increased gas burning bring. This increases the viability of commercial (unsubsidized) wind and solar projects. The state can then use subsidy budgets to fund expensive, yet promising technologies, like offshore wind. 

Because of the country’s policy initiatives, the UK is on track to reduce emissions by 50% over 2015-25 – or earlier, depending on when the last UK coal plant retires. 

Sunnier times ahead for coal workers in renewables, tech

By Bryony Collins at Bloomberg NEF

Image via Bloomberg
Image via Bloomberg

The serene waters of the Lusatian lake district in East Germany, lined by golden sand and winding cycle paths, is far removed from its history as a network of opencast mines. Located just over one hour from Berlin by train, the area that used to be a hotbed of coal mine activity has now been transformed into a vacationer’s paradise, complete with restaurants, hotels and adrenaline-pumping activities. 

Factories for battery cell production are also being proposed for Lusatia, as the region transitions away from coal and seeks new investment and jobs in growing areas of the economy, such as electric vehicles and renewable energy. 

In the U.S., the fast-growing industry for rooftop solar also provides a wealth of new job opportunities for ex-coal workers. Some 250,000 people are employed by the solar industry – an increase of 168% on 2010 levels, according to the National Solar Jobs census 2017. More than half of these employees install solar panels – a role that has many parallels with working in the coal sector, such as technical capability, physical competence and attention to safety. 

The number of wind turbine technician jobs in the U.S. will almost double by 2026, as the market for wind energy continues to grow, according to Xinjiang Goldwind Science & Technology Co. The company has a training program in the U.S. to teach technical and safety qualifications for the deployment of wind turbines, and recognizes the parallels between the skills required to work in the fossil fuel industry and those required to work in wind energy. 

“Working as a miner involves operating and maintaining equipment and conducting repairs as needed, which is also the case for turbine technicians,” David Sale, chief executive of Goldwind Americas wrote in an e-mailed statement to Bloomberg.  “The transferability stems from miners’ aptitude for technical work and thinking, and their familiarity with working in line with important workplace safety measures,” he explained. 

Phasing out coal is a contentious topic in countries like the U.S. and Germany, where many people continue to be employed by the industry. Particularly as the coal sector is backed by influential advocates such as U.S. President Trump, who made reviving the coal industry a central part of his campaign pledge. In Germany, the leader of coal-producing state Brandenburg, Minister President Dietmar Woidke, advocates for a very late coal phase-out, due to the social and economic implications of closing down power plants too quickly with no time to provide alternative avenues of employment.

However, new industries like renewable energy can provide greater job stability as countries increasingly seek to clean up their power systems. This article explores some viable alternatives to working in coal.

Figure 1. Coal accounts for less U.S. power generation year-on-year

Coal accounts for less U.S. power generation year-on-year, Source: EIE

(Source: EIE)

Germany’s coal phase-out

“Employment issues are at the core of why coal is politically-sensitive in Germany”, said Alexander Reitzenstein, policy advisor at E3G, a Berlin-based think tank for the environmental sector. The government is moving to gradually phase out coal mining and coal-fired generation in order to achieve its carbon reduction commitments, but doing so is often at odds with protecting the livelihoods of many of its electorate. 

In the state of Brandenburg, where elections will be held in 2019, around 8,000 people are employed in the lignite industry. Coal jobs are highly unionized in the area and the election outcome is likely to be heavily influenced by politicians’ approaches to the coal phase-out. Proposals by politicians such as Peter Altmaier, Germany’s Minister for Economy and Energy, to invest in large-scale battery cell production factories and innovation hubs for new technologies, are a response to the growing need for new employment opportunities and regeneration of the area. 

Germany’s Coal Commission, established in the government’s coalition treaty, is tasked with setting a coal exit date and coming up with a path to reaching the 2030 climate targets. It has 1.5 billion euros allocated to invest in education, re-skilling and infrastructure to reach those targets – money which could be spent on retraining ex-coal workers in new industries. The date for Germany’s coal phase-out will now be decided in early 2019 and “is currently most likely to be set somewhere between 2035 and 2040,” Reitzenstein told BloombergNEF in an interview. 

Around 30,000 people are employed in Germany’s lignite and hard coal sectors, compared to the 340,000 jobs in renewable energy – but coal jobs are highly-unionized and the sector has a long history of debating on issues of societal importance. Closing coal mines and coal plants will also impact other related sectors, such as energy-intensive industries, and could potentially jeopardize jobs there too, say local politicians. 

West Germany’s successful transition from the hard coal mining that drove its industrial growth in the 1950s and 60s to a more service-based economy could be taken as a useful blueprint for what needs to be done to phase out lignite in the country’s East, although that region “is structurally-weaker, there are more social and economic issues, and less industry,” said Reitzenstein. The hard coal phase-out also occurred gradually over decades, so there was more time to create alternative sectors and to gain societal consent. 

Some mines in West Germany were filled up to be used as farmland thanks to good soil quality, and there are also examples of businesses that previously served the coal industry now serving renewables, said Reitzenstein. For example, Bochum-based Eickhoff Group has diversified away from mining technology to manufacturing wind turbine gear boxes. 

The Zollverein coal mine complex in Essen shows the significance of the coal mining industry to European industrialization and is a source of new jobs and tourism revenue. Visitors can tour the former coal-mining site – now designated as a UNESCO world heritage site – and learn first-hand about the coal mining industry, with tours of the pits, coking plants and even the miners’ housing. 

Investment needed 

East Germany needs “concrete investments” such as in battery facilities, and “public infrastructure investment”, in order to attract private investment and to convince local stakeholders that the federal government is prepared to invest in regeneration, said Reitzenstein. The region views structural change negatively, because “before 1990 the region was very important for coal with more than 100,000 workers, but after reunification, the whole industrial area collapsed,” he explained. 

In addition to new employment opportunities, policy needs to provide strong social support schemes to provide for older workers who may be less able to retrain, he added. Some estimates are that by 2030, two-thirds of coal miners will be retired anyway, so a relatively small amount of people could be seeking new employment, according to E3G.

Swedish utility Vattenfall told BNEF that it will be able to manage the employment reduction as a result of coal plant closure entirely through early retirement. The utility aims to shut down or use alternative fuel for its remaining coal-fired combined heat and power plants in Germany and the Netherlands by 2030, in order to comply with regulation and reduce its CO2 emissions. In Berlin alone, the company will invest 1 million euros per day to transition to new energy and phase out coal, Tuomo Hatakka, senior executive vice president for heat at the utility, said in an interview. 

The Drax coal power plant conversion in the U.K. is an example of how converting facilities to run on less-polluting fuel can be a way of retaining jobs. The 4,000 megawatt facility now has four units powered solely by wood-chip combustion, and previous coal plant workers have been retrained in handling biomass, Will Gardiner, chief executive of Drax, told BNEF in an interview. Drax employs 900 people at its plant in Yorkshire and indirectly supports 6,000 jobs in the region through its supply chain.

Alternative employment

Momentum is building in Lausitz to create alternative opportunities aside from work in the coal sector. A collaboration between Germany’s Fraunhofer Institute and the University of Senftenberg and Cottbus in Lausitz is developing a research cluster around new technology such as energy storage and micro-electronics, aiming to attract new businesses and investment to the area, said Reitzenstein. 

And in South Brandenburg, Dekra SE acquired the Klettwitz racetrack last year with the aim to develop and test autonomous driving. The project aligns with Germany’s automotive industry and its development of electric and autonomous vehicles, and could further propel regional expertise in new technology.

The scale of Germany’s automotive industry and associated supply chain could also act as a good foundation for battery development. Volkswagen is becoming more open to producing the battery cells for electric vehicles under the leadership of Herbert Diess, with some reports suggesting that the company’s pilot cell facility in Salzgitter may be expanded. 

Parts supplier Continental AG is also considering moving into battery cell production, and spinning off its power train division, according to Bloomberg News. Elsewhere, LG Chem’s plan to open Europe’s largest lithium-ion battery factory in the Polish city of Wroclaw could also help propel European knowledge of battery cell production, particularly given its proximity to Germany’s auto industry and coal phase-out. The LG Chem factory will employ 2,500 people and produce 100,000 EV batteries annually, according to a Reuters articlefrom last November.

The spacious and flat landscape of Lausitz is also conducive to building wind farms and solar parks, said Reitzenstein. In Brandenburg alone, around 20,000 people work in renewable energy and there is lots more potential for wind farm development, said Reitzenstein. “Jobs in renewable energy outnumber those in coal, sometimes by tenfold in Germany,” he told BNEF. In the state of North Rhine-Westphalia, where renewable energy is much more developed, there are around 46,000 jobs in renewables, versus just 9,000 in lignite. 

Expansion of existing industry in Lausitz would also increase employment opportunities for ex-coal workers. BASF SE has a chemical industry facility with room for expansion, and Hamburger Rieger GmbH owns a paper-making facility, according to Reitzenstein.

Figure 2. U.S. coal mining work is in decline

U.S. coal mining work is in decline. Source: EIA

(Source: EIA)

U.S. solar

The U.S. rooftop solar industry is expanding quickly, including in states with a large economic presence in coal. Indeed, as the economics of coal become increasingly less attractive and more U.S. coal plants are shut down, the number of jobs in renewables is rapidly outpacing those of the incumbent power sector, including coal. U.S. solar and wind industries currently employ around 475,000 people in the U.S. – three times as many as the coal industry, according to Goldwind. The two industries with highest projected job growth by 2026 are both in renewable energy, projects the U.S. Labor Department.

Rooftop solar companies, Sunrun and Vivint Solar, each employee around 4,000 people in the U.S., with a significant portion of these engaged in service and installation work. Both companies have recruited people previously employed in the coal industry. “There is overlap between the knowledge and experience coal miners possess about tools and machinery and the equipment used in PV installation,” Chad Herring, vice president of talent at Sunrun, told BNEF in an emailed statement. The U.S. Bureau of Labor Statistics reports that 65-70% of jobs in coal mining are not industry-specific, so re-training ex-miners in solar installation is not an extensive process, Herring said. 

Vivint has increased the number of its installation crews by almost 50% in the last five months on the back of strong sales growth in states like California that have supportive legislation for rooftop solar. The company operates in eight of the 25 U.S. coal-producing states, including sun-filled states such as Colorado and Arizona, and sees parallels between the safety and quality standards necessary to coal mining and those requirements found in the solar industry. Vivint provides two to four weeks of technical, on-the-job training to workers without prior knowledge of rooftop solar installation. Sunrun also provides safety and quality training and on average 40 hours of training overall in the first year of employment, according to Herring. For employees that come to Sunrun without prior experience of installing solar panels, the company “provides the required training and certifications needed for them to succeed,” said Herring. Installers and technicians are an “integral part” of Sunrun’s business in states that see big drops in coal mining jobs, such as Maryland, New Mexico and Texas, he added.

Wind

Goldwind’s training program for wind energy technicians in the U.S. demonstrates the fast growth of the sector and the need to retrain technical employees in skills related to a relatively new industry. The company is actively recruiting technicians to work at projects in Texas, Ohio, Illinois, Vermont and Montana and will be offering training on its two-week programs for successful individuals, said Sale.

“When we first began Goldwind Works we anticipated a large influx of applicants of unemployed individuals directly from coal-related companies, but what we came to find was that many other ancillary industries were also impacted by the downturn in the demand for coal,” Sale said in a statement. “We saw applicants ranging from land surveyors and fire fighters, to truck drivers and mechanics, all looking to move into a more stable, growing industry like wind.”

Goldwind plans to expand the program outside the U.S. to Canada and possibly Mexico as turbine contracts are secured, he said.

UK retreats from coal, helped along by Drax plant conversion to biomass

By Bryony Collins at Bloomberg NEF

Image via Bloomberg
Image via Bloomberg

The UK is rapidly retiring the coal-fired relics of its industrial past and moving toward a future where days with zero coal-fired generation are the norm. Coal plants accounted for less than 1 percent of UK electricity in June 2018, as a spell of cloudless days led to lots of solar power generated, and a subsequent decrease in demand for thermal power. 

Set among the rolling hills of Yorkshire, the Drax power plant is an example of how power stations can be retooled to run on alternative fuel. Over the last decade or so, the 4-gigawatt plant has gradually been converted to run on biomass instead of coal. As of August 2018, four of the six units at the Drax plant in Yorkshire are powered by wood pellets – making the power station the “largest single source of renewable power in the UK”, Will Gardiner, chief executive at Drax, told BNEF in an interview. Overall, the Drax plant generates about 6% of UK electricity and enough renewable electricity for four million households. 

Watch the interview of Will Gardiner, CEO, Drax

BNEF Executive interview: Will Gardiner, CEO, Drax from Bloomberg NEF on Vimeo.

The plan is for the final two units to be converted to run on natural gas in the next 12 to 18 months, dependent on planning permission and the success of Drax winning a contract to provide extra capacity to National Grid, said Gardiner. 

The company wants to drop all reliance on coal power in line with the UK government’s pledge to be coal-free by 2025, while also supporting the integration of a new flexible and low-carbon electricity system. Converting its final two coal units to high efficiency combine cycle gas turbines, combined with as much as 200MW of battery storage, would allow Drax to provide flexible capacity to the grid as more renewables ebb and flow on the system, said Gardiner.  

Initially, the repowered gas units would deliver 3.6GW of baseload capacity to the National Grid and “over time, as more renewables come onto the system – they might act more as a peaking plant,” said Gardiner.

Drax receives government subsidies in the form of Renewable Obligation Certificates (ROCs) and Contracts for Difference (CfDs) to improve the economics of its biomass-fired units, but post-2027 the goal is to operate subsidy-free. A lot of cost reduction will come from the supply chain for biomass, said Gardner. The aim is to replace the expensive dried and compacted wood pellets used today with sawmill residues that are cheaper and require less processing, he explained. “Between 30% and 40% of the wood fiber that goes into a sawmill becomes sawdust or residues” that Drax could burn in its power plant to generate renewable power, said Gardiner. 

Biomass-fired power at Drax currently costs around 75 pounds ($100) per megawatt-hour, and the aim is to reduce that to around 50 pounds per MWh to enable the plant to operate subsidy-free, said Gardiner. 

Waste product is inexpensive and would otherwise have been burnt or have decomposed in a short period of time, so the carbon emissions are effectively the same as what they would otherwise have been, but with the added advantage of generating power, explained Gardiner. In contrast, burning coal is effectively “releasing into the atmosphere carbon that has been locked underground for millions of years,” he added.

Drax currently sources its wood pellets from forests in the southern U.S., where trees grow at a faster rate than they are being harvested, which results in a net decrease of carbon in the atmosphere. 

Carbon taxes and emission control requirements in the UK combine to make the economics of running coal plants less attractive than powering plants with natural gas or biomass – both of which emit significantly less CO2, and in the case of the latter even receive government subsidies.  

Drax has received subsidies in the form of ROCs and CfDs to improve the economics of converting its biomass units over the last couple of years. Overall, the company invested some 700 million pounds ($920 million) in converting the units. A “major part of the investment was the fuel handling piece – transporting the biomass from the entrance to the power station and into the boilers”, whereas the turbine generators and boilers remain the same regardless of the fuel type used, Gardiner said. 

Drax was able to reduce the cost of converting the fourth unit to biomass by re-using the infrastructure for co-firing biomass that was installed several years ago, when the company first envisaged using biomass generation. This included a rail unloading building with conveyor systems that transport the wood pellets several kilometers to the final power generation units. 

As long as the economics of natural gas remain attractive and the carbon price remains relatively high, there is a strong likelihood that the UK will be able to transition completely off coal by 2025 or before, said Gardiner. Efforts to transition away from coal to biomass will help this transition. 

Similarly, plans to convert the 360MW Uskmouth coal power station in Wales to run instead on waste-to-energy pellets is another example of a coal plant transitioning away to a less carbon intensive fuel.

South Korea’s environmental ambition tackles the coal challenge

By David Kang at Bloomberg NEF

Image via Bloomberg
Image via Bloomberg

Coal generation has long served as a crucial component of South Korea’s economy by providing a cheap and reliable source of electricity to the country’s fast-growing manufacturing and service industries. As a result, the total capacity of coal-fired power plants has doubled to 37 gigawatts in the past two decades and coal generation accounted for the largest share (45%) of Korea’s generation mix in 2017.

National movement to phase out coal

To reduce its historic dependence on coal, the world’s fourth-largest coal importer has embarked on an ambitious energy transition to fuel its economy with more environmentally-friendly energy sources, including liquefied natural gas (LNG) and renewable energy. According to the government’s new long-term energy plan, also known as the 8thBPE (Basic Plan for Electricity Supply and Demand), Korea aims to increase the share of gas and renewables in the generation mix to 39% while lowering that of coal to 36% by 2030. Given that nine coal-fired power plants that are already under construction are set to add a net five gigawatts of new coal capacity into the power mix by 2022, Korea’s long-term roadmap to reduce its dependence on coal will require significant investment and support from both the government and economic actors.

Figure 1. Korea’s 8th Basic Plan for Electricity Supply and Demand (8th BPE)

Korea’s 8th Basic Plan for Electricity Supply and Demand (8th BPE). Source: Korea Ministry of Trade, Industry and Energy

(Source: Korea Ministry of Trade, Industry and Energy)

President Moon Jae-in, who strongly advocated the phase-out of coal and nuclear during the election campaign, has been actively implementing follow-up policy measures to help enable the envisioned energy transition. Since the Moon administration took office in May 2017, the government has scrapped plans for two new coal-fired power plants and converted them to gas plants. The Ministry of Energy also decided to temporarily shut down ten aged coal plants during spring season and launched a new regulation that limits the maximum output of 42 coal plants across the country below 80% when the fine dust level in the atmosphere rises to a harmful point. Policy initiatives are also affecting the economics of coal generation. According to a draft energy tax code proposed by the government, Korea plans to increase the fuel tax on thermal coal by 28% while lowering the tax on LNG by 75%. Based on the analysis conducted by BloombergNEF, coal generation will still remain on-average cheaper to run than gas generation, which consequently limits the policy’s impact on the power market if the rates remain unchanged. Nevertheless, given the highly contentious nature of large tax revisions, the proposed tax code is clearly a positive indication that reflects the country’s commitment to a cleaner power system.

Limitation and outlook

Despite the various top-down policies and bottom-up efforts that are driving the transformation of Korea’s power system, the existing inertia and the country’s inflexible power market will likely hinder the rapid transition that the nation envisions. BNEF’s New Energy Outlook (NEO) 2018, a bottom-up least-cost modelling, suggest that coal generation would continue to grow until 2027 in absolute terms as a result of the coming online of the new coal plants that are currently in the pipeline, and the little room the installed capacity leaves for new renewable energy investment. Without stronger policy intervention, coal will still be the dominant source of electricity in 2030. 

Figure 2. South Korea’s power generation mix

South Korea’s power generation mix. Source: Bloomberg NEF

(Source: Bloomberg NEF)

Stronger push coming from bottom-up

Building on the momentum brought by the new central government, South Chungcheong province has taken a step further and joined the Powering Past Coal Alliance (PPCA) in October 2018. As a province that is home to half of Korea’s coal-fired power plants, South Chungcheong is not only the first jurisdiction in Asia to join the alliance but also the largest coal power user to have joined the PPCA since its foundation in 2017. 

As part of South Chungcheong’s ‘2050 Energy Vision Plan’, the province vowed to shut down 14 coal power plants that amount to 18 gigawatts of capacity by 2026 while increasing the share of renewable energy in its power mix to 48% from the current 8%. The decommissioning of 18 gigawatts of coal by 2026 would reduce South Korea’s coal capacity to 22 gigawatts, as opposed to the 40 gigawatts online now, creating opportunities for more investment in renewables and gas.  Although the success of this roadmap will largely hinge on the central government’s willingness to revise the subsequent national energy roadmap, including the 9thBPE, the decision taken by South Chungcheong province shows that policy makers are willing to set bold objectives that will accelerate the phase-out of coal.

The ambition of the South Chungcheong province may well encourage other provinces and the national government to revise theirs and is a clear sign of the appetite for more aggressive policy initiatives. At a national level, the government should complement the temporary shutdowns and the conversion of two new coal plants to gas plants, with a more fundamental restructuring of the power market that correctly reflects the externalities of coal generation, such as the environmental and health costs, to accelerate South Korea’s phase out of coal.

Indian coal power faces long-term headwinds

By Atin Jain at Bloomberg NEF

India Solar thermal power plant. Credit Brahma Kumaris/Flikr
India Solar thermal power plant. Credit Brahma Kumaris/Flikr

India’s coal power generation story started 98 years ago with the commissioning of Hussain Sagar Thermal Power Station in Hyderabad in 1920. India kept adding coal capacity at a gradual pace after that and had reached 71 gigawatts of coal power generation capacity by 2007. Then, over the subsequent 11 years, an explosion of capacity additions resulted in more than 130 gigawatts of new coal plants coming online.

The last peak annual capacity additions was 2015, when 19 gigawatts of coal power plants were added in India. Annual net additions have been declining since then. In 2017, India added more renewable power generation capacity than coal fired capacity for the first time ever and is expected to repeat the feat in 2018. This is the beginning of a new trend and BloombergNEF expects renewables will always outcompete coal power on an annual build basis in the future. Today, 196 gigawatts of grid-connected coal-fired power stations supply about three quarters of the total electricity requirement in the country.

Figure 1 - Net annual power generation capacity additions in India

(Source: Bloomberg NEF, Central Electricity Authority. Note: *Data up to June 2018.)

Rising fuel costs, low fleet utilization and air pollution regulations are making coal power economics unattractive

Coal became the workhorse of the power sector due to the promise of low-cost power supply the country desperately needed. However, the economics of coal power generation are under stress due to the rising costs of coal supplies, a drop in the capacity utilization factor (CUF) of power plants and new emissions regulations.

Transport costs make up more than a third of the landed cost of coal supplied to the power plants. These costs have more than doubled over the last 10 years, leading to an increase in the power generation costs. In future, we expect transport costs to increase faster than the basic run-of-mine coal price. This will continue to increase the cost of power generation from coal plants. 

The coal fleet utilization dropped from 77.5% in fiscal 2010 to 60.6% in 2019, due to excessive capacity build out and slower-than-expected growth in power demand. A decrease in CUF of a coal plant leads to an increase in the cost of power generation. BNEF estimates that the levelized cost of electricity (LCOE) of a new Indian coal power plant increases by 18% with a drop in CUF from 80% to 60%. 

Figure 2 & Figure 3 - Capacity utilization factor of Indian coal fleet (left) and impact of changing capacity factors on the levelized cost of electricity of coal plants (right)

 

(Source: Bloomberg NEF, Ministry of Power. FYY2019 is April 2018 to March 2019. Capacity utilization factor data for FY2019 is till August 2018.)

New emission mandates from the government aimed at reducing sulfur dioxide, nitrogen oxides and particulate emissions from power plants will require the installation of emission control equipment such as flue gas desulfurization plants, selective catalytic reduction units/low NOx burners, electrostatic precipitators etc. at the power plants. We estimate that these installations can increase the levelized cost of electricity from coal by as much as 9%, depending on the choice of emission control technologies.

New renewables are already cheaper than new coal power in India

Solar and wind power are already the cheapest form of new power generation sources in India. Some of the cheapest new-build solar and wind farms are even cheaper than running many of the existing coal-fired stations in India. Power from new solar and wind plants in India is being procured at fixed nominal tariffs for 25 years. Conversely, the coal power tariff usually increases every year due to higher energy charges (such as landed fuel costs) of the generating stations.

Figure 4 - Levelized cost of electricity from competing power technologies in India

(Source: Bloomberg NEF. Note: 1$ = 67.93 rupees. The range of LCOEs represent the range of costs, capacity factors and other project design parameters. The LCOEs represented here are unsubsidized nominal first year LCOEs for fair representation of value from each generation source. For all technologies it is assumed that the tariff escalates in each year of operation by CPI. This is very different from renewable prices discovered in Indian auctions, which usually remain fixed for 25 years.)

Renewables will add more generation capacity than coal annually in future

The long-term outlook for coal power generation looks weak as the challenges facing the coal sector will persist in future. The economic competitiveness of renewable power sources as a bulk power generation source has led to cancellations of many proposed coal power plants in India. 

The demand for power will continue to grow in future, but new coal capacity additions and an explosive growth in competing renewable power technologies like solar and wind will lead to a persistent supply glut of coal power. This will keep the CUFs of Indian coal fleet suppressed in the short term.

Around 36-40 gigawatts of coal projects are currently under construction and will come online in the next five years. Coal capacity additions is expected to slow down after that. While capacity additions will ease off, the retirements of coal fleet will accelerate. The Central Electricity Authority in its National Electricity Plan 2018 expects 48 gigawatts of coal-based generation capacity to retire by March 2027.

Due to the air pollution concerns, coal projects are not expected to go for life extensions through renovation and modernization, but will be retired at the end of their economic life.

Figure 5 - Projected gross capacity additions and retirements of Indian fleet

(Source: Bloomberg NEF)

While coal projects already under construction will come online, albeit with a delay in commissioning, it is becoming increasingly difficult to conceive and plan for new coal projects. Land acquisition for coal power projects (and mines) is becoming more difficult due to local community protests. Sourcing water and fuel supply for the projects is another major hurdle. Almost all under-construction coal projects are delayed, with many of them overdue by more than five years. The interest rates for long-term debt to coal projects have gone up and surpassed those for renewables in the last few years as lenders factor in these issues when deciding on the premiums. The bad experience of the banking sector with non-performing coal assets has further led to a reluctance amongst the lending community to finance new coal projects.

Renewables will supply three quarters of India’s total electricity demand by 2050

Based on our long-term economic forecasts of India’s power system, we expect renewable energy sources (including hydro) can supply 75% of India’s total electricity needs by 2050. Solar and wind are expected to supply a third each of the total power demand. The share of coal will drop to just 14% in 2050 from 75% in 2017.

Figure 6 - Expected electricity generation from different power generation sources in India

(Source: Bloomberg NEF)

Supply-chain constraints are adding to the power plant operator woes

Indian coal power sector faces regular supply-chain issues. Power plants do not receive the full quota of fuel under their supply agreements with Coal India and other domestic suppliers. The miners are unable to meet their production targets. The government wanted Coal India to produce 1 billion metric tons of coal by fiscal 2020. However, the company has pushed back this target to 2026 due to India’s rapidly evolving electricity supply mix, air pollution reduction targets, challenges in land acquisition and slow industrial demand. 

The supply-chain issues are not just restricted to production challenges. Indian Railways is regularly confronted by train shortages and network constraints. Indian coal plants are unable to maintain enough fuel stock due to these reasons and many Indian coal power plants are forced to shut down due to coal shortages. The plant closures and fuel shortages have led to power cuts in many parts of the country in recent times. Even the spot power prices in wholesale markets went up to record highs due to low power generation from coal plants and high seasonal power demand.

The government last year ordered state-owned power companies to stop thermal coal imports and was trying to convince IPPs to source their coal needs from domestic sources only. But the supply shortages prompted many utilities and IPPs to resume coal imports to meet their fuel needs. Contrary to government ambitions, India’s thermal coal imports are growing at the fastest pace in the last three years and went up by 35% in July-September 2018 over 2017. This was during a time when the international coal prices were at a six-year high.

Leading coal power producers and miners are investing in renewables

Major Indian and international companies are realizing the long-term implications of cheap renewables on the future power mix of India and are looking to invest large amounts of capital to set up solar and wind power plants in the country. The ever increasing challenges in building and running coal plants are just making these decisions easier for the companies. Some of the most striking plans for renewable deployment in the country come from India’s largest power generating utility – NTPC Ltd. – and world’s largest coal miner – Coal India Ltd.

NTPC currently has 46 gigawatts of coal plants and is looking to add another 19 gigawatts of thermal capacity over the next five years. But these plans are dwarfed by the company’s ambition to add 32 gigawatts of renewable energy capacity by 2032, which would constitute a quarter of its total fleet of 130 gigawatts by 2032. NTPC used to conduct auctions for renewable power and procure power from IPPs due to government mandates. Now, the company is itself participating as a developer in auctions by other bidding agencies and plans to utilize its expertise in power project development. Recently, Coal India and Neyveli Lignite Corp. announced a partnership to set up 3GW of solar power capacity. 

The National Tariff Policy 2016 suggests that any coal based power producer should also set up an equivalent renewable energy capacity as a part of their renewable generation obligations. In future, this should also lead to a higher deployment of renewables from other coal IPPs and utilities.

India can achieve peak power sector carbon emissions in early 2030s

The surge of renewables and a retreat of coal power in the future will result in India achieving peak power sector carbon emissions in the next 15 years, even without additional policies. Carbon emissions are expected to go up by 29% from 2017 levels and peak in 2033. By 2050, emissions would be 22% lower than in 2017.

Figure 7 - Power sector carbon emissions in India

(Source: Bloomberg NEF)

These developments give very strong and clear signals about the inevitable transition of India’s fossil fuel power generation to a clean and sustainable power mix. This transition to cleaner power mix will be faster than previously anticipated and will create long-term opportunities for investments in clean energy technologies.