China’s New Carbon Market

October 2021

Economists have long argued for Carbon Markets as a tool for reducing Greenhouse Gas emissions, yet politicians have been reluctant to follow their advice. Many economists must have celebrated on July 20 of this year, when China launched what is potentially the world’s largest Carbon Market. With China now accounting for over 25% of the world’s total GHG emissions, if economists are right, this might be a huge step towards slowing climate change. A hundred days into this grand experiment, Infrastructure Ideas takes a look at how start-up is going.

Headquartered at the Shanghai Environment and Energy Exchange, China’s new National Emissions Trading Scheme (ETS), or Carbon Market, is based on a cap-and-trade model. Some 2,000-plus coal and gas-fired electricity generation plants – initially the sole participants in the ETS – have been allocated emissions allowances up to a government-set maximum, and are now free to either sell these allowances if they keep emissions below their cap, or forced to purchase additional allowances if they will exceed their maximum. The new national market is the successor to a series of city and provincial-level emissions trading schemes in operation in China since 2013.

While the new Carbon Market have drawn considerable fanfare as an important part of China’s energy transition, reviews to date of its impact have been mixed. Concerns about the scheme maybe being a mouse rather than a lion have centered on the ETS’ (a) design, (b) prices and trading volumes, and (c) enforcement and penalties.

Design. Most national carbon trading systems work by giving participants an absolute level of emissions – this absolute cap cannot be exceeded without either penalties or the purchase of further allowances. The Chinese ETS instead is designed to limit the intensity of emissions per unit of energy, and not aggregate emissions. This means that as consumption and production of energy grow, emissions are also potentially allowed to grow, albeit more slowly than production. Clearly in the short run, at least, this means carbon dioxide emissions are likely to exceed what they would if firms were given a starting “hard cap.” Greater efficiency, or lower carbon-intensity in electricity production is a good thing, but whether and when it actually reduces emissions will depend on how incentives – and therefore prices for allowances and penalties for non-compliance — evolve. Chinese authorities would have to force significant efficiency gains – by, for example, reducing the allowed emissions per unit of energy – from the system’s starting point for the market to be a major force.
Prices and trading volume. Trading in the new market was launched in July at a unit price of just over $7 per ton of carbon dioxide emitted. Prices since then have declined slightly from that level, and ranged generally between $5 to $8/ton. This is one of the lowest levels for carbon prices on any of the 45 existing carbon exchanges worldwide, higher than only those for trading in Japan and Kazakhstan. Prices in the EU carbon market have been ranging from $50 to $70/ton (though one should note that prices in the US Regional Greenhouse Gas Initiative market are also around $7-8/ton). The International Monetary Fund also estimates that the price of carbon credits will need to reach around $50/ton to effectively drive down the country’s carbon emissions. The low prices to date are a direct result of the issuance of large starting volumes of allowances, which come close to matching the overall emissions of the participants. The large supply of allowances, along with low prices, has also contributed to very limited trading volumes – with few emitters feeling the incentive or need to participate yet. While one can understand why authorities may have preferred to see low prices initially to minimize disruptions for participants, disruption for emitters is precisely the outcome which many would like to see (for more, see Nature’s “Is China’s new carbon market ambitious enough?”). The impact of the market in the future will likely depend to a great extent on the evolution of allowance prices: if allowances to firms are kept at initial levels (or even reduced) over time, while production grows to accommodate economic growth and additional demand for electricity, then prices may rise substantially – in turn creating a much stronger incentive for producers to find efficiencies and not allow GHG emissions to grow.

Enforcement and Penalties. The verdict remains very much out as to whether enforcement of emission limits under the ETS will be substantive, or not. On the one hand, in general China’s enforcement of central government policies tends to be fairly strong. On the other hand, there have been widespread reports of companies in the earlier regional and local carbon trading schemes falsifying emissions data. The new national scheme is said to put a greater emphasis on monitoring and evaluating emissions data, and features the use of independent monitoring firms. The future will tell whether this, combined with potentially higher trading prices over time, is enough to help the market have a significant impact.

In spite of the underwhelming start and these concerns, there remains considerable hope that this new Carbon Market will begin to have a much greater influence, and an impact in reducing GHG emissions. Hopes rest mostly on (a) market size, (b) the design of annual adjustments, and (c) signaling effects.

Size. While the initial participants in the market are only one part of one sector in a large and complex economy, they are still an enormous part of the world’s carbon dioxide problem. Between them, the 2,000+ coal and gas-fired generation companies involved in the market’s launch emit some 4 billion tons of CO2 annually, about 10% of all global emissions from all sources. This already dwarfs the potential reach of all existing carbon markets. And while no firm timetable has been disclosed, it has been announced that the ETS will expand to cover large Chinese firms in seven additional sectors: petroleum refining, chemicals, non-ferrous metal processing, building materials, iron and steel, pulp and paper, and aviation. These sectors have combined emissions on a par with the power companies. So if the initial issues with the market can be overcome, the impact on curbing emissions from the world’s biggest GHG emitting country could be major.
Design. While the basic design choice of not using absolute emissions caps gives rise to concerns, much hope lies in another element of the system’s design. Each year, companies’ allowed per-unit GHG emissions are to be recalculated and reduced, which would drive greater efficiency by requiring them to reduce the amount of emissions they generate for the energy they produce. This means that the Government has a clear, simple and repeatedly available tool to shape the speed at which the companies reduce their carbon-intensity. Should policy-makers decide that emissions need to be reduced faster than the pace being delivered by the market, they can force more action, and can do so on an ongoing basis. In this sense, China’s Carbon Market is very Chinese – a market which expects frequent government intervention.
Signaling. The explicit features of the new Chinese Carbon Market do not point to a big early impact on emissions. Yet China being China, it would be a mistake to underestimate the effect of the system’s implicit features. The Chinese leadership, and Xi Jinping personally, have taken highly visible positions on China’s climate targets, and the link from Xi’s commitments and the ETS has not gone unnoticed. Several generation companies trading on the new exchange have accordingly pledged to accelerate a strategic “green” shift, including two of China’s “Big Five,” China Huaneng and China Huadian. The country’s coal sector is, after all, dominated by state-owned enterprises. The signals from the top may sound a lot louder to these SOEs than they sound to economists.

A hundred days in to the world’s largest emissions trading scheme, reactions are pretty muted. Most experts expect it will take years before China’s program matures into an effective tool for curbing emissions. Yet, again, this is China. In terms of containing emissions, and moving towards the stated national goal of carbon neutrality by 2060, the explicit mechanisms of the Carbon Market are probably less important than the country’s formal planning process, and China’s 5-year plans at national, regional and sectoral levels. With nudging from the top, China’s Carbon Market may yet turn into a very big deal.

Xi Jinping’s UN Coal Pledge

September 2021

On September 21, at the United Nations General Assembly in New York, Chinese President Xi Jinping announced that China would cease financing coal-fired power plants overseas. In today’s column, we’ll look at why this announcement is at the same time both less and more important than it sounds.

Hot air?

Let’s start with what the UN announcement does not do. The big item, of course, is that this is about support for coal-fired generation outside of China, not inside of China. Capacity and emissions from coal-fired plants supported overseas by China account for less than 5% of those of the country’s domestic fleet. China’s 1,000 Gigawatts (GW) of domestic coal-fired power production accounts for more than 50% of the world’s total, and the emissions from this sector are the largest contributor to rising greenhouse gases today. In 2020 alone, China commissioned 38.4 GW of new coal plants, 76% of the global total of new coal-fired power plants, according to the non-profit organization Global Energy Monitor – roughly equal to its overseas pipeline. Emissions savings pale in comparison to China’s domestic coal use.

The announcement, as is often the case from China’s leadership, is short on details. While it seems fairly clear this will apply to support for new projects at the planning stages, it is not yet clear whether it will also apply to financial support for projects under construction, which at some 15 GW is a very large number by itself.

The announcement also, clearly, does not apply to the 65+GW supported by China and already in operation. A recent report by Boston University estimates that coal-fired plants financed overseas from 2000 to 2018 will generate 11.8 Gigatons of carbon dioxide. Efforts to keep global emissions below a 1.5 degree pathway will likely require the early closure of some of this capacity, a topic only now receiving attention.

Or pretty cool?

These substantive concerns aside, let’s look at what makes the UN announcement a big deal. Starting with the fact that China is, by far and away and increasingly, the world’s largest financier of coal-fired generation. This is in line with China’s increasingly dominant position in financing emerging market infrastructure, with its capital flows far larger than that of the international development community since 2000 (see “Where did all the Chinese money go?”). From 2000 to 2018, China financed an estimated 14% of all the coal-fired plant built outside of the country; in 2020, an estimate by Nature found that 85% of all cross-border financing for coal power flowed from China – 42 GW. China has been, in the words of another Boston University study, “the new coal champion of the world.”

As noted earlier, the UN announcement is short on detail, so understanding exact numbers implied is tricky. All the estimates, however, involve very large numbers. Global Energy Monitor (GEM), a U.S. think tank, believes the announcement could affect 44 coal plants earmarked for Chinese state financing, with capital costs of $50 billion, and with the potential to reduce future carbon dioxide emissions by 200 million tons a year. That’s equivalent to about 15% of 2020 GHG emissions from the entire US coal fleet, or more than the annual GHG emissions of some 150 countries.

The numbers and impact are even bigger when we consider that China’s announcement is the tail end of multiple major announcements related to coal financing in 2020 and 2021. These have included (a) the US’ announcement that it would oppose coal financing from the multilateral development banks in which it is the largest (or one of the largest) shareholders – a symbolically important announcement, even though MDBs have steered away from the sector, (b) JBIC’s April 2020 commitment to end new coal power plant financing, and (c) South Korea’s April 2021 pledge to cease export coal power finance for the Export–Import Bank of Korea, the Korea Trade Insurance Corporation and the Korea Development Bank. As the Institute for Energy Economics and Financial Economics (IEEFA) notes, it was government capital subsidies from China, along with Japan and South Korea, that underwrote almost every new coal power plant built globally in the last five years.

The announcement is an even bigger deal in the Asian countries which have depended on Chinese coal financing as a lynchpin of their power sector strategies. As Infrastructure Ideas has previously written, essentially all the countries contemplating large new coal-fired capacity investments are in the middle of critical energy transitions, and wrestling with several factors as to whether to implement coal-fired generation plans, or whether to turn instead to renewables and/or natural gas for their growing needs. For Indonesia, Pakistan, Bangladesh, and Vietnam, the disappearance of Chinese financial support is likely to be a deciding factor in their decision-making on energy sector policy, and likely to significantly hasten the pace of their decarbonization. Along with Turkey, and China itself, these four countries account for more than 80% of the global pipeline of new coal-fired power generation.

Indonesia has the largest coal power pre-construction pipeline, according to IEEFA, at over 10 GW, with another 8 GW planned based on either Japanese or domestic financing. Indonesia also has large hydropower, geothermal, wind and solar potential, but its energy transition has stalled due to a combination of vested interests, large domestic coal reserves, and reluctance from its conservative, vertically integrated state power utility, PLN (for more, see “Asia’s Energy Transformation: Indonesia”). With crying needs to increase infrastructure investment across many sectors, diverting capital to replace Chinese financing of new coal-fired plants would have high political costs. Pakistan is probably the largest recipient of coal-fired financing since the start of China’s Belt and Road Initiative (BRI), and is at once home to large deposits of low-quality coal and the country with one of the highest electricity tariffs in Asia. A significant internal constituency in Pakistan would like to keep developing more coal and associated power plants, yet the country is struggling with the costs of recently built coal-fired stations – for which it is seeking debt relief from China – and with a current excess supply of power (for more, see “Asia’s Energy Transformation: Pakistan”). Cessation of Chinese financial support makes it highly unlikely that additional coal plants will be built. Bangladesh was the largest recipient of Chinese financing for coal in 2020, for 10.5 GW. The country has been in the midst of an internal policy struggle about building further coal-fired plants, between the rapid development of natural gas and solar power alternatives and its own vulnerability to the impacts of climate change (for more, see “Asia’s Energy Transformation: Bangladesh”). It was already likely that the plants financed in 2020 would not go forward, and China’s UN announcement makes this almost certain. Vietnam has the largest pre-construction coal-fired pipeline, of 19 GW according to IEEFA, although only about 1/3 was contemplated to be financed by China. Here, the decision by Japan not to support further overseas coal facilities, and the reluctance of both private sector banks and multilaterals – notably the Asian Development Bank (ADB) — to take the reputational risks associated with coal financing, may both have greater impact than China’s own decision. China’s announcement however makes it even more difficult for any private sector banks or multilaterals to propose new coal financing. Vietnam’s state-owned utility, EVN, does have interests in further coal development, and the country has the internal resources to possibly finance one or two new plants. The absence of external financing for coal does however make it much more likely that Vietnam instead expands both its world-class offshore and onshore wind resources, and natural gas-fired power generation (for more, see “Asia’s Energy Transformation: Vietnam”).

While China’s announcement may make the greatest overall impact through these four countries, there are several others whose potential coal plans are likely to be changed. Turkey and Zimbabwe, for example, have between them plans for another 15 GW of new coal plants, but no reasonable prospects of either external or domestic finance for these.

The Big Picture

In 2015, the world-wide pipeline of planned new coal-fired plants was estimated at over 1,500 Gigawatts – equal to almost ¾ of existing global coal-fired capacity. Construction and operation of all these new plants would have practically guaranteed a scenario of global warming of over 3 degrees or more. With a combination of domestic policy changes in many countries, and the withdrawal of essentially all but China from coal financing, that pipeline had shrunk to a much smaller but still considerable about 300 GW by mid-2021, according to the NGO Carbon Tracker. Close to 1,200 GW, or 75% of the 2015 pipeline, has been cancelled since 2015. With China’s UN announcement, at least 15% or 50 GW, and possibly more, of the remaining coal-fired pipeline is likely to disappear. This does not solve the global problem of meeting emission reduction targets, but it is a sizeable step in the right direction. Next up? Efforts to reduce the coal pipeline further, with an increasingly narrowed focus on India and China domestically. And efforts to take offline existing coal-fired capacity faster (see “Money is Coming for Coal.”).

Much of China’s substantial overseas infrastructure financing over the last two decades has gone to support coal-fired generation: in 2015, almost half of all the BRI’s energy financing went to coal, according to the International Institute for Green Finance, a Beijing-based think tank. As Infrastructure Ideas earlier noted in our “Ten Infrastructure Predictions for 2021: the BRI Gets a Facelift”, this support for coal was creating increasing tension with President Xi Jinping’s desire to for China to seen as a global leader on climate change issues. China’s flagship international initiative, the BRI, has seen increased criticism of its environmental and climate impacts. Announcing some sort of “greening” of the BRI going forward was clearly low hanging fruit for Xi. Already in April Liu Guiping, deputy governor of the People’s Bank of China, told a press conference that China would implement green investment principles for the Belt and Road Initiative. Yet the UN announcement is not the end of Chinese overseas support for energy in emerging markets. China will be seeking to replace coal financing with “green infrastructure” financing, a set of sectors in which it is already often the world’s leader. Going forward, look if anything for a new “bubble” of financing support for renewable energy projects in emerging markets, as China joins an already crowded bandwagon.

Index of Previous Columns on Energy Markets

Index of Previous Columns on Climate Adaptation

Asia’s Energy Transformation: Vietnam

June 2021

As the climate keeps warming, many in the United States and Europe are taking a long list of actions and arguing for more. How hot the earth gets, however, more than anyplace else, hinges on the actions taken – or not taken – in Asia. Asia has the world’s largest population, the world’s fastest growing economy, and – for climate, more important than anything else – close to 80% of the world’s coal-fired generation. The path Asia takes – and takes in this decade – will do more to determine the path of climate change the rest of the century. The path Asia takes, in turn, depends on the path that its own large economies take. Infrastructure Ideas has previously examined the dynamics of the energy transformation, especially whether countries will or will not add yet more coal-burning electricity capacity, in India, Pakistan, Bangladesh, and Indonesia. Today we’ll look at another of the region’s critical economies: Vietnam.

Vietnam’s population of 97 million ranks 15^th in the world, and its energy consumption growth of over 10% a year the last several decades has been one of the 5 highest in the world. As population and incomes continue to rise, the demand for electricity in the country is expected to more than double by 2030. Generation capacity is expected likewise to more than double, from the current 55 gigawatts to 130 GW, at an estimated cost of US$150 billion – and then to more than double again by 2045, to 277 GW. Coal-fired generation is the largest source of power in Vietnam, accounting for about 53% of demand. Aside from coal, hydropower accounts for about ¼ of capacity, according to the IEA. Natural gas makes up some 16% of demand, and non-hydro renewables about 7%.

Coal in Vietnam is not only the largest source of power in the country, it has also been the fastest growing, with capacity having increasing by nearly 15 times since 2005, to about 25 GW in 2019. As the ability to build more large dams along the Mekong River basin has become very constrained, the government increasingly has turned to new coal plants instead of hydropower. With the expected strong growth in future electricity demand, Vietnam’s earlier power sector plans called for building more than another 45 GW of new coal-fired generation capacity by 2030, which would nearly triple the country’s existing coal fleet. According to Bloomberg New Energy Finance, Vietnam’s coal-fired pipeline is the 4^th largest in the world today, with some 17 GW under construction and another 29 GW in advanced planning stages. This comes to about 15% of the total planned new coal capacity worldwide, excluding China, and if built, these plants would contribute to adding annual emissions of some 500 metric tons a year of CO2. Enough to make the world significantly hotter.

Energy policy in Vietnam, fortunately, is in transition. The country continues to envisage rapid further growth in electricity consumption as it develops, but where that added electricity is to come from is changing fast. In the past two years, Vietnam has gone from almost entirely fossil-fuel and hydropower-based to a solar and wind powerhouse. With a different sequence than most of the world, Vietnam moved first to aggressively adopt solar generation, especially rooftop solar. From less than 2 GW of capacity in 2016, solar generation capacity now exceeds 11 GW – 5 GW of which was installed just in 2020. Vietnam even showed the third-biggest growth in rooftop solar installations globally in 2020. Yet the biggest energy headlines for Vietnam are now elsewhere – in offshore wind. Onshore wind plants in Vietnam have begun to appear, but sites are constrained by the lack of available land. The country has turned its eyes offshore, as the offshore wind sector has begun to mature worldwide (see Infrastructure Ideas’ Offshore Wind – the Next Big Thing). In 2021, Vietnam is forecast to install 1 GW of wind capacity, triple its existing capacity and surpassing Thailand—at present Southeast Asia’s front-runner in installed wind capacity. And in July 2020, the Vietnamese government approved the assessment of the area off the cape of Kê Gà in south Vietnam to build the world’s largest offshore wind farm with a capacity of 3,400 MW – larger than any existing generating facility in the country.

With – at last – renewables coming to Vietnam, the country’s planners are rethinking Vietnam’s large-scale plans for future coal-fired generation. Several factors are coming into play: (a) the government has seen that investors and banks will finance new wind and solar generation, and that this source of power is cheaper than it had expected; (b) internal demand is geographically uneven, with both demand and growth highest in the south of the country – where offshore wind potential is the greatest; (c) the communist government is also ill-at-ease with both recent demonstrations against coal-fired power station projects, and with the risk of electricity shortages – with fossil-fueled capacity taking much longer to bring online than wind and solar; (d) sources of external capital to finance new coal plants are getting harder to come by; and (e) Vietnam itself stands to be heavily impacted by sea-level rise, with its extensive low-lying urban and agricultural areas along the Mekong Delta.

The government’s evolving thinking has begun to take shape in the draft form of “PDP-8,” its eighth multi-year Power Development Plan. Released in February 2021, the draft calls for both wind and solar generation capacity to rise to about 20 GW each by 2030, with their share of generation jumping from about 7% today to 30% by 2045. Coal, as a share of the country’s generation mix, is projected to be cut in half, to about 27%. The National Steering Committee for Power Development has recommended eliminating about 15 gigawatts of planned new coal plants by 2025, according to the state-controlled news website VietnamPlus. The draft PDP-8 proposes no new coal-fired power plants except those already under construction or planned for completion by 2025 or sooner. This would still, however, leave almost 20 GW of new coal capacity to come online this decade. And the battle for how to meet yet another doubling of demand in the following decade has not been joined.

As the planners deliberate, the environment around Vietnam keeps changing as well. For one, financing for coal plants continues to get more complicated. Japan has been a big financier of the sector in Vietnam, but Mitsubishi – one of Japan’s largest players in coal — announced in February it would no longer support one 2 GW and $2B flagship coal project, Vinh Tan 3. Conversely, financiers are eager to finance renewable generation: two wind power plants, Phu Lac 2 and Loi Hai 2, just this month closed a financial package from the IFC. For another, Vietnam has not really seen yet how cheap wind and solar power have become around the world. A late-comer to renewables procurement, Vietnam still offers a feed-in tariff mechanism to project developers, at 8.5 cents per kilowatt-hour – more than triple what it costs to procure new wind power capacity in the United States. As it moves this year to more efficient auction mechanisms for new capacity, and assuming it improves its PPA framework, Vietnam should start seeing renewable prices far lower than what it has been paying to date. And thirdly, Vietnam has yet to dip its toes into energy storage. As costs continue to plunge and availability expand, battery storage could help Vietnam meet its growing electricity demand with significantly less future expansion of new generation capacity.

Vietnam completed its five-year general elections for the National Assembly in May. By the end of June, the government is expected to release the final version of PDP-8. In a largely state-controlled economy such as Vietnam’s, formal government plans rule the roost, and PDP-8 will determine whether Vietnam sticks to earlier plans to move full steam ahead with building large-volume and high-emission new coal generation, or whether it will continue to cut back on new coal plans and switch even more strongly in the direction of renewable energy. A great deal – of emissions and climate change – hinges on the decision, and on Vietnam’s continued energy transition.

Previous Infrastructure Ideas Posts on Energy: Index

Money for Coal

March 2020

At least in Germany.

In October 2019, Infrastructure Ideas flagged a coming decommissioning wave for coal plants, and projected a future where coal-fired power plants are paid not to generate electricity, but to stop doing so. In January, that future arrived. As reported by the New York Times and others (How Hard Is It to Quit Coal? For Germany, 18 Years and $44 Billion), Germany approved on January 29 a plan to pay coal workers, companies, and producing states $44 Billion to close producing plants before the end of their technical life. Producing companies will receive $4.8 billion over the course of the next 15 years in compensation for shuttering their coal-burning plants, some of which will be replaced by natural gas-burning generators. The plan foresees taking 19 coal-burning power plants offline in the coming decade, beginning with the dirtiest plants later this year.

coal-exit-path-capacity-closures-felixmatthes1

This plan goes far beyond the one floated in Germany in the Fall of 2019 to use auctions to fix costs for early coal plant retirements. That plan had some attractive features, including the use of market mechanisms to reduce the cost of the program, but was judged to still leave too large a residual problem. In other words, Germany concluded that a voluntary program would leave too many coal-fired plants still operating, and they were willing to pay the cost of a mandatory one. That same dynamic is likely to play out at the larger global scale: market-based incentives, such as Germany’s reverse auctions, may well be a useful tool to begin the process of early coal-plant retirements; but mandatory, and negotiated, closures will be necessary – and probably on a much-larger scale than voluntary closures.

What can we learn from Germany’s experiment?

1. There is a lot of pressure from climate and environmental groups to take action against coal-fired electricity generation. Germany arguably has one of the largest concentrations of such groups, and it is not surprising that the first concrete plan should be found here. But that pressure can be expected to intensify and broaden geographically. German pressure was fueled in part by signs that the country was falling well short of its announced emission reduction targets (see McKinsey’s analysis on this topic). The same signs are apparent in much of the world.
2. Voluntary plans – the centerpiece of global climate negotiations to date, including the Paris Agreement – only take you so far. Mandatory plans for energy transition are needed to create impacts in line with climate objectives.
3. A forum that allows multiple voices to be heard – in this case the “German Coal Commission,” which worked for two years on crafting and negotiating an outcome that could be as widely supported as possible – plays a major role in crafting any “mandatory” agreement.
4. The technical costs involved with fast-tracking coal plant shutdowns are high, but not nearly as high as the costs of adjustment for workers and regions that have come to depend on coal for their livelihoods. In the case of Germany, a whopping 90% of the $44 billion plan is headed elsewhere than the generation companies who will be shuttering their plants.
5. The bill is high for putting in place a mandatory plan in a fair and consensual way. The German plan puts a price tag of around $1B per GW of coal-fired power retired.
6. For all its ambition and its hard-won consensus, the German plan may still wind up reopened. There are provisions for periodic domestic review of the plan and its execution. And there may well be international calls for speeding up the timetable, if global emission and warming projections worsen – which we believe they will. Either of these two could lead to higher costs than now contemplated for the plan.

Today Germany, tomorrow the world?

Aside from the German plan, there was related news in January that the European Union aims to create a €100 billion fund to aid the transition of Eastern European countries to cleaner fuels. This was a centerpiece of the much-discussed “European Green Deal.” The EU’s “Platform for Coal Regions in Transition” works similarly to the German Coal Commission, as a forum for working out details of transition and compensation for affected parties, to be embedded in a “Just Transition Mechanism”.

The details of the proposed EU plan illustrate an important additional lesson beyond that of Germany. Finding the money to finance this type of climate change-driven transition will be enormously complicated. While the overall envelope for funding envisaged is roughly in line with that of the German plan – about $1B per Gigawatt of generation capacity to be retired – the funding mechanics are very different. Whereas the $44B German plan simply call for payments from the state budget, the €100B EU plan calls for only €7.5 of direct EU funding, to be leveraged by loans (some from the EIB), national budgets, and funds from yet-to-be-found investors. The basic principle of leverage is generally a good one – an early US state plan for retiring coal capacity, in Colorado, aims to manage associated costs by de-facto borrowing from ratepayers — but in this case sounds highly aspirational, and conveys a sense of considerable fragility in the future implementation of the EU plan. Just yesterday, the EU admitted it would take a “herculean effort” to make the plan work.

South Africa has also floated a “green plan” to shut down coal-generating capacity – if other countries will pay it to do so, as previously flagged by Infrastructure Ideas. However, the Government backed away from this idea in the October 2019 release of its next electricity “integrated resource plan,” keeping earlier blueprints for continued adding of coal-fired generation capacity. The dropping – for now – of the idea to sell Eskom’s loss-making coal fleet to “climate investors” has been ascribed to the inability to find a domestic political consensus, with Eskom’s unions reportedly leading the opposition. The plan now on the table leaves unaddressed the issue of Eskom’s near-bankrupt financial state and some $30B in debts, and so shares a high degree of aspirational thinking with the EU’s plan for Eastern Europe.

The pressure underlying these first “pay for coal” plans is going to increase, and increase rapidly. Coal-fired power generation continues to be the single largest emitter of greenhouse gases, accounting for 30% of all energy-related carbon dioxide emissions. In all climate models, phasing out coal from the electricity sector is the single most important step to get in line with holding global warming to 1.5 or even 2 degrees, and as time passes it is increasingly clear that canceling potential new coal plants will not be enough. The late 2019 report from Climate Analytics shows a need to go from current global coal-fired generation of 9,200 Terrawatt-hours all the way down to 2,000 TWH by 2030 – equivalent to decommissioning about 1,600 GW of generation capacity. Applying the cost of the German plan, $1B/GW, would imply costs on the order of $1.6 trillion to shut down this much global capacity.

We would expect such plans for fast-tracking of coal plant retirements – now that at least Germany there is a tangible model — to become the centerpiece of climate change discussions at the next COP summit, and to rapidly rise to the top of the agenda for multilaterals such as the World Bank. The experience of Germany, the EU, and South Africa points to a number of things we can expect for these discussions:

1. Forums that include bottom-up elements, and not just top-down planning, will be essential to the crafting of workable plans.
2. The bulk of any financing associated with these plans will be not for technical closing costs, but for worker and regional adjustment plans.
3. The financing amounts involved will be enormous. The $44B price tag for Germany’s plan is roughly equal to 4-5 years total generation sector investment, while the broad global estimated $1.6T price tag would be around 3 times annual global power generation investment.
4. Financing mechanics will be very complicated and contentious to devise. Germany’s financing approach – we’ll pay for it out of our own budget – is likely to be rare, if not unique. We can expect many false starts, and far more dead-end ideas than ones that get a serious hearing. Cross-regional and cross-country aspects will increase complexities (who will want to pay to retire China’s coal plants?). It may be a very long time before a workable solution for most, if not all, of the targeted retirement amounts is found – if it is found. The passage of time in finding viable financing mechanisms will mean emissions staying well-above aspirational climate targets, and in turn lead to a feedback loop where political pressure continues to build.
5. Financing for this energy transition ultimately will involve massive amounts of public financing, and that will mean a lot less public money available to invest in other infrastructure. Decommissioning coal-fired plants will become a massive competitor for infrastructure-related financing in the coming two decades.

Money for coal. It’s coming, and it won’t be easy. Stay tuned.

Blue Coal ?

Blue Coal?
October 2019

In the first two parts of this series, Infrastructure Ideas reviewed prospects for the coal industry, and forecast that the decommissioning of coal-fired generating plants would become a major destination of infrastructure (and climate-related) investment before long. In this third and last piece of the series, we focus on some possible unexpected political fallout from coal’s situation.

The central development to consider, in understanding how the sunset of coal is likely to affect politics, is its lack of economic competitiveness. In past decades, with coal cheaper s a source of electricity than other alternatives, the logic to politics was to be anti-government: the biggest threat to coal economics, and to coal jobs, was seen as government regulations. Not surprisingly, the stronger climate and pollution concerns became, the more strident the anti-government intervention politics of coal became. But economics are a wholly different threat. Coal-fired generation in the US is shrinking rapidly. In Europe, a recent report claims 4 out of every 5 coal-fired plants is losing money (Apocalypse Now, by Carbon Tracker). With the change in economics, the politics will change too. In the US, the beginning of this change became visible in the first two years of the Trump administration, with the odd couple of a conservative White House – elsewhere completely focused on dismantling government regulations — advocating in this case for government intervention, in the form of price supports for coal-fired electricity. Again not surprisingly, this strange strategy was dead on arrival – it went against the grain of both strong economic trends and the rest of the Republican agenda.

As coal becomes both uneconomic and a growing target for climate change concerns, we are likely to see political realignment. Coal will receive public funding, as in the US the current Republican administration has sought. But it will receive it for different reasons, and driven by different politics. What we will increasingly see is a drive for the use of public funding not to keep coal going, but to shut it down. And, crucially for the politics, for using the public funding also to help adjustment of the workforce in the coal industry. For Democrats, using public funds to intervene in the economy has long been a staple of policy, and now counteracting climate change is as well. With the likely acceleration of public concerns over climate change (see part I of this series), decommissioning coal is also likely to become a top policy priority for Democrats. Which implies that both owners of coal plants, and workers in the industry – now facing large-scale closures and loss of jobs — will in the future look for support not to their traditional republican allies but to democrats. Money makes for strange bedfellows…

One of the western US states with many coal plants both coming to the end of their life and/or becoming uneconomic is Colorado, and the state has shown one replicable way forward in managing associated tensions that could work for other coal-intensive locations (see Colorado May Have a Winning Formula on Early Coal Plant Retirements). While coal has been a key source of both energy and employment for decades, Colorado has been seeing wind power purchase contracts coming in at extraordinarily low levels, between $0.015-0.025 per kilowatt-hour, and even bids to provide a combination of solar power plus storage at under 4 cents/Kwh – almost half the cost of what electricity from new coal-fired plants would be. Colorado’s new plan is to use securitization from ratepayer-backed bonds to pay out decommissioning plants, and then to reserve some of the bond income for helping workers in affected areas. The bonds pay out the equity base of old plants from the utilities. While this piece of the mechanism has been tested before, the important complementary part of Colorado’s approach is the creation of something called the “Colorado Energy Impact Assistance Authority,” which will focus on helping workers displaced by the decommissioning.

Another example of changing political discussions around coal can be found in Arizona. There one of the largest coal-fired plants in the US, the Navajo Generating Station, is closing due to the loss of customers. Utilities in the region have shifted to wind and solar to save money. A bill introduced last month in the US House of Representatives (see the IEEFA’s Bill to Spark Federal Post-Coal Reinvestment in Arizona Tribal Communities Is a Good Beginning) calls for federal economic development and revenue replacement in the wake of the collapse of the coal industry in northern Arizona. The bill would fund large-scale clean-up and remediation around both the plant and its associated mine, Kayenta, continuing employment for many of the current workers (the power plant and mine are by a wide margin the largest employers of Navajo, with about 750 workers between them). It would also retool the existing transmission infrastructure towards solar power generation. Funding would go to tribal and local governments to compensate for losses due to decommissioning under a schedule that would replace 80 % of lost revenue initially, reducing by 10% annually. The IEEFA review of the bill notes it “could very well serve as a template for broader bipartisan legislation supporting federal reinvestment in coalfield communities nationally, including in Kentucky and West Virginia and the Powder River Basin of Montana and Wyoming, regions that are taking disproportionately heavy casualties as power-generation demand for coal recedes and local coal-based economies adjust to new market realities.”

Of particular note is that the Arizona bill was introduced by congressman Tom O’Halleran – who began his career as a Republican, and switched to the Democratic party.

It is way too early to tell whether either the Colorado or Arizona approaches will be a model for other regions. But what is clear is that the issues the two states are addressing are going to become very widespread – and faster than most people realize. It is also clear that similar approaches – with public intervention to accelerate and smooth the transition away from coal – will be the only alternative to bankruptcy for plant owners and unmitigated layoffs for workers. And it is clear that the amount of public resources needed to help both owners and workers will be very large. Not something a party bent on shrinking government is likely to manage. Look for coal country to start turning… Blue.

The Coming Decommissioning Wave

The Coming Decommissioning Wave
October 2019

Our previous Infrastructure Ideas column (What Next for Coal?) outlined the (declining) state of the coal-fired electricity generation business. Driven until now by the age of plants and weakening economics, this decline is about to be sharply accelerated by climate concerns. An important consequence of this acceleration will be the impact and costs of decommissioning old – and not so old – generation facilities. The funds required for this decommissioning will be in the hundreds of billions of dollars. Decommissioning, in fact, will likely become one of the largest areas of infrastructure-related financing in the coming decades! Why is this going to happen, and how will it work? Read on…

Power plants close all the time. Since 2000, over 3,000 generating units have closed just in the United States. Historically these closures have been primarily end-of-technical-life retirements, with the post WWII building boom and average expected plant life of around 40 years. More are scheduled to close in coming years: another 6,000 plants in the US have been in production over 40 years, representing about 1/3 of national generating capacity.

What has begun to change is the rationale for closing generating plants. Already, economics – as opposed to just end-of-technical-life – has become a major factor in closing facilities. This is a predictable outcome of a sector which has gone from essentially stable to highly dynamic – driven by technology change (see Not Your Father’s Infrastructure). As prices of electricity from newly-built plants continue to plummet, the higher costs of power from older generating plants are becoming much more visible and problematic for buyers and policy-makers.

The first group of generating facilities to feel this economic pressure has been, interestingly, wind farms. The early generation of wind farms, often built to meet local environmental concerns and with output priced at a premium in most electricity markets, are now vastly more expensive than the newly-built wind farms (or solar). As they come to the end of their initial sales contracts, keeping these wind farms in service is economically unattractive. The first of these farms were coming on stream in the late 1990s, often with 15- or 20-years Power Purchase Agreements and typically being paid on the basis of pre-set Feed-in-Tariffs; they are now coming to the end of those contracts. 2015 was the first year that saw considerable wind farm retirements in the US, with an average plant life of 15 – as opposed to 40 – years. Germany, a country which was an early leader in pushing a “green energy” agenda, has a large-scale version of this issue. 20-year FITs will expire beginning in 2020 for over 20,000 onshore wind turbines, with a collective capacity of 2.4 gigawatts. Owners face decisions of whether to retire the wind farms or repower them (another potential option involves corporate PPAs, along the lines of the recent contract signed between Statkraft and Daimler, whereby Daimler will buy – for a 3 to 5-year period – power from wind farms whose guaranteed FIT contracts are expiring). Elsewhere, repowering of wind turbines has become a major business. Repowering began as replacement of old turbines with taller, and more efficient machines on existing sites; today operators switch even newer machines for larger and upgraded turbines or replacing other components. This makes sense where acquisition of land for new sites may be difficult, and where revenues are contingent on being able to compete with new lower-cost alternatives. In 2018 over a gigawatt of wind capacity was repowered in the US, and an estimated half gigawatt was repowered in Europe. The economic pressure to replace early-generation and more expensive renewables with new and cheaper plants extends well beyond Western Europe and 20-year old wind farms. FITs, the preferred first generation of purchase contracts for wind farms and some solar, have come to be seen as highly unfavorable to buyers, as costs of new equipment kept falling. Spain in the early 2010s, Portugal and several Eastern European countries either forced retroactive changes to purchase contracts or terminated them prematurely, trying to reduce the fiscal costs of expensive early renewable contracts. Yet even with competitive auctions replacing FITs, there remain economically-based risks to contracts. In India, the new state government in Andhra Pradesh has sought to terminate purchase contracts for solar power which are less than five years old. As prices for new solar and wind capacity, and for associated storage, continue to fall, this pressure will be more widespread.

The bigger losers from the economic pressure to switch power supplies, however, are clearly producers of thermal power. In the few places which still reply on oil to fire generation plants, the cost differential between existing supply and new alternatives is massive. In Kenya, the Government has announced its intention to shut several expensive oil-fired plants, starting with long-established and pioneering IPPs such as Iberafrica, Tsavo and Kipevu-diesel. With Senegal and other relatively small markets demonstrating that the option of below 5 cent/kilowatt-hour solar is a reality practically everywhere, we should expect a wave of closures of older oil-fired plants – whose costs run upwards of 15 cents/KwH. Globally, though, oil-fired plants make up a tiny part of electricity capacity. The biggest losers are rather in coal.

Many coal-fired plants have been closing for end-of-life technical reasons. From 2000 to 2015, over 50 gigawatts of coal-fired capacity was closed just in the US, with average closed plant life of over 50 years. More recently, coal – long seen as the cheapest form of electricity supply – has also begun to be supplanted on economic grounds. In the US natural gas-fired plants have come to be widely preferred. Endesa, in Spain, announced two weeks ago that it would shut down 7.5 gigawatts of coal power; the main reason cited was declining competitiveness, noting that its sales of coal power had declined 50% in the previous year. These are large amounts: Endesa has flagged a write-down of over $1 billion related to the retirements. Yet these amounts are still ripples compared with the coming wave.

What will drive a major acceleration of coal-fired plant closures is the continued worsening of economics, and a third factor, coming on top of technical retirements and economic pressures. This third factor is climate concerns. On economics, as discussed in our previous post, various analyses in the US show that costs of electricity could be reduced by closing between 1/3 and 2/3 of the existing coal fleet today, with that share rising to 85% by 2025 and 96% (about 250 gigawatts) by 2030. Regardless of how precisely accurate these estimates are, it is fairly clear that an amount of coal-fired capacity far larger than that retired since 2000 is or is about to become uneconomic compared to alternatives. Coal is not getting cheaper, but wind and solar, and storage, continue to get much cheaper. The big killer, though, we expect will be climate concerns.

The latest IPCC report, along with several others issued in conjunction with last month’s Climate Week, is fueling more concerns about the pace and likely extent of climate change. New data on the pace of climate change and GHG emissions levels is alarming. Every new analysis shows climate change is proceeding faster than previously expected, and pathways to lower-impact carbon concentration and temperature change require larger shifts than in previous analyses. The International Energy Association’s latest annual review found that as a result of higher energy consumption, 2018 global energy-related CO2 emissions increased to 33.1 Gigatons of CO2, rather than decreasing as they had from 2014 to 2016. The IEA also found that climate change is already causing a negative feedback loop in emissions: they estimated that weather conditions were responsible for almost 1/5th of the increase in global energy demand, as average winter and summer temperatures in some regions approached or exceeded historical records – driving up demand for heating and cooling alike, while lower-carbon options did not scale fast enough to meet the rise in demand. Another report coordinated by the World Meteorological Organization, says current plans would lead to a rise in average global temperatures of between 2.9C and 3.4C by 2100, more than double the level targeted in the Paris agreements. The trend seems clear, and before long public concerns will drive much more aggressive public policies.

Coal-fired power generation continues to be the single largest emitter, accounting for 30% of all energy-related carbon dioxide emissions. In all analyses, phasing out coal from the electricity sector is the single most important step to get in line with 1.5°C, and recommendations are getting steadily more strident and draconian. Canceling potential new coal plants will clearly not be enough. Another report from last month, this one by Climate Analytics states that although the new coal pipeline shrunk by 75% since the adoption of the Paris Agreement, to get on a 1.5°C pathway will require shutting down coal plants before the end of their technical lifetime. The report’s models show a need to go from current global coal-fired generation of 9,200 Terrawatt-hours all the way down to 2,000 TWH by 2030 – equivalent to decommissioning about 1.6 Terrawatts (1,600 Gigawatts) of generation capacity. Still another report modeled the need for emissions from coal power to peak in 2020 and fall to zero by 2040 if the world is to meet the Paris goals. Shutting down so much coal-fired generation capacity is a tall order. Yet the political pressure in this direction is building. Several countries in Europe have announced coal phase-out plans: France for 2022; Italy, the U.K. and Ireland for 2025; Denmark, Spain, the Netherlands, Portugal and Finland for 2030, and Germany for 2038. Even coal-rich South Africa is studying a plan involving substantial closures.

This potential decommissioning wave would be very expensive. Closing a coal-fired plant is a high cost exercise. The write-down associated with Endesa’s closures in Spain, noted above, comes to about $200/ KW of capacity. Resources for the Future in 2017 issued a detailed analysis of decommissioning costs for power stations in the US, coming up with a range of observed costs for coal of $21 to $460/KW of capacity, and a mean cost of $117, and estimated future decommissioning costs of between $50-150/ KW. These estimates are slightly lower than the costs indicated by Endesa, but are in the same ballpark, and we can get a rough idea of aggregate costs by applying a midpoint (say $100/KW) to the global coal fleet. This gives us the following projections:

• For retiring 250 gigawatt of coal generation capacity in the US, an implied a cost of $25 billion.
• For retiring 1,600 gigawatt of coal generation capacity around the world, an implied cost of $160 billion.

These costs are large… but are only a part of the picture. The analysis here includes the engineering specific costs, essentially technical and environmental costs associated with shutting down a plant, and cleaning up its site. It does not include other important costs associated with decommissioning, namely labor force and community adjustment costs, and – most critically for newer facilities – foregone revenue and breakage costs. For worker retraining and support, and adjustment funding for affected communities and regions, there are no clear estimates available. Germany’s decommissioning roadmap calls for about $40B in support to affected regions over 20 years, so we can see that the numbers – assuming governments aim to help – are not small. That $40B is greater than the estimated technical costs of retiring the entire US coal fleet. For a ballpark estimate, we could then say:

• For retiring 1,600 gigawatt of coal generation capacity around the world, an implied cost – including community/regional adjustment support — of $300 billion or more.

This still leaves the cost of foregone revenues for those who built and own the plants. In markets where many of the plants are approaching technical end-of-life, these costs may be low. Same in merchant markets where coal is losing customers on the basis of economics, and renewables and/or gas-fired plants are reaching significant scale. But in Asia, where the average age of the coal-fired fleet is closer to 10 years rather than 40, this is going to be a significant factor. If one assumes each megawatt of coal generation capacity has cost about $1M, and has associated equity of around $250,000 and debt of around $750,000, we can do a back-of-the envelope estimate of breakage costs for some 800 GW of “younger” Asian coal plants:

• At an annual rate of return target of 7.5%, with 30 years yet to go, potential future flows to equity over 30 more years would amount to about… $500 billion.
• Assuming average initial debt maturities of about 15 years, so that 2/3 of debt would already be repaid, this would leave outstanding principal debt in the range of … $200 billion

Obviously there are multiple assumptions embedded throughout these estimates. What they serve to show, however, is that the costs associated decommissioning the existing global coal fleet over the next two decades – assuming public opinion and politics coalesce around the issue, which we expect to happen – are very high. As in close to $1 trillion. Not to mention another trillion or so to build substitute renewable energy generation capacity. Annual investment today for comparison, around the world, in renewable energy? Less than $300 billion.

There are a few ideas already, at a local level, about how decommissioning costs might be funded. Germany’s roadmap includes reverse auctions for closure subsidies, where those bidding for the lowest amount of support would get funding. Eventually, plants not winning support at these auctions would be forced to close without state subsidies. Costs of legal challenges have not yet been considered. South Africa’s potential roadmap envisages donor and financial institution support to create a fund, managed by Eskom, to finance adjustment in coal-heavy parts of the country, support workers, and help balance Eskom’s finances during the transition away from coal. Colorado has a plan whereby securitization from ratepayer-backed bonds would pay out plants, and some of the bond income would go for helping workers in affected areas.

However these ideas play out, one thing is highly likely: decommissioning coal-fired plants will become a massive competitor for infrastructure-related financing in the coming two decades. The public portion of these costs – whether through a Global Fund, country-or regional specific vehicles, or just government spending – are very likely to exceed cumulative subsidies offered to renewable energy projects in their early years. A lot of funding, and a lot of creativity, will be absorbed here.

What Next for Coal?

What next for coal?
October 2019

On November 9, 2016, many coal companies threw a party. As a candidate, Donald Trump repeatedly told cheering crowds he would “stop the war on coal,” bring back coal mining jobs and revitalize communities in the Midwest and Appalachia that depended on coal mines. Shares of mining and associated equipment and transport companies soared overnight. The late Chris Cline, once described as the “last coal tycoon,” was so pleased that he immediately contributed a million dollars to the inaugural celebration for Trump.

The party’s over.

Production of coal in the US in 2019 is forecast to be the lowest in 40 years, and has fallen 30% since 2010. Bankruptcies of previously celebrating companies are coming almost monthly. In May of this year, Cloud Peak Energy — one of the largest US coal miners, declared bankruptcy; its mines shipped 50 million tons of coal in 2018. In the recently concluded bankruptcy auction, lenders to Cloud Peak will get $16m in cash… for their over $300m in outstanding debts. In July, another large producer, Blackjewel, also filed. Large mines in the Powder River Basin and the Eastern US were closed. Two more large producers, Arch Coal and Peabody Energy, agreed in June to consolidate their seven mines as a strategy to remain in business. All of this 2019 activity comes on the heel of the October 2018 bankruptcy filing of Westmoreland Coal, the largest independent coal producer in the US: there being no bidders at auction, creditors holding $1.4 billion in claims have been left to try operate the company’s assets themselves to try and recover some cash.

The problem for the mines is the departure of customers, especially in the power industry. In the same US where Trump pledged to bring back coal, no one is investing either in coal-fired plants or coal mines. But plenty of these are closing, accounting for almost half of all coal-fired power plant closures worldwide. And as reported in September by Energy and Environment News, the size of the closed electricity plants is increasing (And Now the Really Big Coal Plants Begin to Close). Navajo Generating Station, which closed the first of three of its units in late September, will be one of the largest carbon emitters to ever close in American history. It will join the Bruce Mansfield plant in Pennsylvania and the Paradise plant in Kentucky as plants that have emitted over 100 million tons of carbon dioxide since 2010 and that will have shut down. Multi-state western utility PacifiCorp announced last week that it would close large power-fired plants in Montana, Colorado and Wyoming – in one case two decades ahead of schedule. In the Southeast US, the picture is the same as in the West: a report this week from IEEFA (Coal-Fired Generation in Freefall across Southeast US) notes a net decline of 48 since 2008 in the number of coal-fired generating plants in the region, with the share of coal generation dropping from 48% to 28% during that period.

The White House narrative on coal was, and continues to be, about regulation. But what happened to coal was not regulation – it was technology. First came the new technologies for drilling for natural gas (commonly lumped under “fracking,” but in practice a much broader set of technology breakthroughs, especially related to imaging of underground deposits), which increasingly made new coal-fired electricity generation uncompetitive with gas-fired electricity. Natural gas plants could also be turned on and off far faster than coal-fired electricity generators, meaning that gas rather than coal was in demand to act as “peak capacity,” when hourly demand from consumers would be above average and need to be closely matched by production. Then came the technology breakthroughs that drove down wind and solar generation costs, enabling electricity from new wind and solar plants to come in at costs less than half that from new coal plants. With new technology also sending energy storage costs plummeting, it will only get worse for coal.

Outside the US, the story for coal is similar: many country-level variants, especially in Asia, but the direction is the same. A report from Global Energy Monitor noted that the number of coal plants on which construction has begun each year has fallen by 84% since 2015, and 39% just in 2018, while the number of completed plants has dropped by more than half since 2015. Infrastructure Ideas’ series on the energy transition in Asia outlined how key policy choices under consideration may affect demand in many of the handful of countries where possible new coal generation is concentrated, namely India, Indonesia, Bangladesh and Pakistan. A study by Carbon Tracker estimated that nearly half of China’s existing coal power fleet is losing money, and that it will become more expensive to operate coal in China than to build new renewables by 2021. A report issued in March by Energy Innovation and Vibrant Clean Energy claimed that replacing 74% of US coal plants with wind and solar power would immediately reduce power costs, at times cutting the cost almost in half. According to the analysis, by 2025, over 85% of coal plants could be at risk of cheaper replacement by renewables. Carbon Tracker came up with similar in a November global analysis of 6,685 coal plants. This found that it is today cheaper to build new renewable generation than to run 35% of coal-fired plants worldwide. By 2030, that increases dramatically, with renewables beating out 96% of today’s existing and planned coal-fired generation. Exceptions remain only in markets with extremely low fuel costs, where coal is cheap and plentiful, or with uncertain policies for renewables, like Russia.

For coal-based power companies, there is no longer much of a future in planning and building new plants. Revenues are declining as a number of existing plants are retired as they reach end-of-life, as we keep seeing in the US. With prices of electricity from natural gas-fired plants remaining low, and prices from new wind and solar plants continuing to fall, more existing coal-fired plants are becoming economically uncompetitive, and either running at low capacity or also being closed, though their technical end-of-life may still be several years away. So the future looks increasingly unprofitable.

There may, however, be an unexpected silver lining. Coal-based power producers may well have another big potential revenue stream out there. Just not the one anyone has been foreseeing, or one that has been there before. That potential source of new revenue? Getting paid to take plants offline. Sound odd? Indeed. There are, however, two big building blocks towards this possible future.

1) There’s a lot of coal left to retire, even with fairly high current retirement levels. China has more than 1 million Megawatts, or 1,000 Gigawatts, of capacity operating or under construction, while the US has over 250 Gigawatts left and the EU has over 150 GWs. And key policy choices in some Asian countries may lead to yet more build-out for a time.

2) Political pressure for action is going to get very high. New data on the pace of climate change and GHG emissions levels is unidirectionally alarming. Every new review of climate change finds it to be proceeding faster than previously expected, and emissions levels remain well-above scenarios for lower levels of temperature rise. With every passing year, potential mitigation plans will become more and more aggressive, calling for faster and deeper cuts in emissions.

Faster and deeper cuts in global GHG emissions are highly unlikely to be achievable without early retirement of the large existing coal-fired fleet. And changing economics do not always translate rapidly into retirement of existing producers. Which makes it likely that at some point, in the not too distant future, closing existing plants faster than they would close on their own will become a top public policy priority. Closing existing plants might be done by political fiat, or, it could be done by paying coal-fired plants to go away. It may well prove that paying them could be a faster way to achieve closure, avoiding drawn-out litigation around contractual rights.

For coal executives, the best hope for offset continued revenue decreases may well be to hope for the creation of a publicly-funded “close coal plants now” funds. It does sound odd, but it may well be their best bet. And in the US, which political party is most likely to favor using increased public funding to achieve a policy objective? It’s not the current occupants of the White House.

Difficult to conceive, but it may come to be: coal executives for… Democrats?

Infrastructure Ideas will explore these plant retirement issues in its next two posts of this series: The Coming Decommissioning Wave, and Blue Coal?

Asia’s Energy Transformation: India

Asia’s Energy Transformation: India
August 2019

This is the fourth in a series on the ongoing, large-scale transformation of energy use in Asia. Previous columns have focused on Pakistan, Bangladesh and Indonesia. As we noted in earlier installments of the series, Asia is the most important global market for energy consumption, investment, and greenhouse-gas emissions. And it is a region undergoing a large-scale energy transition, whose unclear evolution has more importance to the future of both climate change and energy investments than that of any other region.

With over 1.3 billion people, India is the world’s second most populated country, and accounts for about 18% of all the people who live on earth. Somewhere around 2024 India will become the most populated of all. Yet it consumes only about 5% of the electricity produced globally. About 200 million people in India live without electricity, and about twice as many have access for less than six hours a day. Prime Minister Narendra Modi, elected in 2014, has made it a priority to change this, and provide universal electrification in India. Plans provide for roughly a tripling of the country’s electricity generation over the next two decades, a central plank to India’s development and poverty-reduction efforts. Good.

When Prime Minister Modi took office, 2/3 of all power produced in India was generated from coal. Were the plan to triple power generation to succeed the same profile of where power comes from, it would imply adding more greenhouse gas emissions annually than the amount produced annually by the United States. Bad. So Modi has also proposed an unprecedented ramp-up in renewable energy generation. India’s ability to raise electricity availability is critical to development and poverty reduction, yet how it does so will also have a crucial impact on the global environment. So India’s energy challenge is one in which both India and the rest of the world have a huge stake.

The good news is that so far, India’s bet on renewable energy has succeeded far better than most observers expected. Five years ago, when Modi was elected, India’s total renewable energy production capacity was 34 GW, about 10% of its power capacity, mostly consisting of hydropower, with solar capacity at a tiny 1.5 GW. Today renewable energy capacity stands at 80 GW, with essentially all the growth having come from solar and wind farms. This has vaulted India up to 5th globally in renewable energy production, behind China, the USA, Brazil, and Germany, and 4th (ahead of Brazil) if hydropower is excluded. The country’s well-publicized 2022 renewable energy target (just three years from now) is 175 GW, more than double current capacity – and about equal to current combined wind and solar capacity of the USA, or to the world’s total generation capacity from wind and solar power a short decade ago. Doubling wind and solar capacity in three years would seem nearly impossible – except for the fact that this is exactly what India has done over the previous three years.

A big part of this success story, as has been the case in other countries bringing on stream large amount of solar and wind power, has been rapid price decreases. As renewable auctions got underway in Brazil, South Africa, and other places, driving costs down by 75% in 3-4 years in several countries, India seemed like it would be on the outside looking in at the renewables boom. With high foreign exchange risks, government bureaucracy, and loss-making state-owned electricity distribution companies, analysts initially thought India would find it hard to bring solar costs down below $0.10/KwH – double what some countries were seeing, and well above the cost of alternative ways to raise electricity production, mainly through coal. Yet India managed to become a part of the global solar boom, with prices dropping almost monthly for three years. The cheapest prices offered for generating solar have come down to $0.036/KwH (still double world lows – see And Prices Keep Falling), or about half of what power from a greenfield coal-fired plant could be expected to cost.

In a country as large as India, with states as politically diverse as it has, it is unsurprising that adoption of renewables has varied widely across the country. Rajasthan and Gujarat have two of the largest solar programs and the lowest prices. Tamil Nadu’s late 2017 solar auctions brought signed offtake agreements at $0.054/KwH, compared to previous capacity additions there at $0.12. Renewables there are set to account for 35% of total generation capacity in the state. Karnataka and Telangana each added 2 GW in 2018. Several states, however, have no solar generation at all. The government of one state, Andhra Pradesh (AP), has managed to be good news and bad news all in one. On the one hand AP announced a very large short-term target of installing 18 Gigawatts of renewable energy by 2022, almost 20% of the total national target for the period, and tripling AP renewable capacity. Good news. On the other hand, in May newly elected AP Chief Minister Jaganmohan Reddy called for retrospective renegotiations and cancellation of existing contracts for wind, solar and storage contracts in the state. Bad news. At issue is that prices for renewable capacity contracted in the previous 5-6 years are now much higher than prices based on rapidly advancing technology. Not that previously contracted prices are particularly high in AP – tariffs being contested are in the range of 5-8 cents/KwH. These are still attractive prices relative to power generation costs in many countries. The AP problem, however, which is not unique to AP, is that a combination of gross inefficiencies in the state-owned power distribution companies (India has the highest grid losses of any country in Asia, at an average of 25%) and subsidized prices for some consumers means that state-owned distribution companies are virtually bankrupt, and the new Chief Minister seeks to squeeze improvements any way he can. Andhra Pradesh Southern Power Distribution Company (APSPDL) and Andhra Pradesh Eastern Power Distribution Company (APEPDCL), have lost $220m together in the last year. You can see the political logic driving him, but the cost in lawsuits, and the driving away of operators from AP – reducing competition for future capacity bids – is likely to be a very steep price for breaking contracts. As India looks to achieve its 175 GW target for renewable capacity by 2022, and equally ambitious capacity growth targets beyond this, the roadblocks that have stymied even faster growth will have to be overcome.

Roadblock #1 to faster renewable growth in India is the coal lobby. This consists of many actors, the most powerful of which is Coal India Limited, who among other things provides significant tax revenue and employment in India’s poorest states. Indian Railways transports most coal and over-charge for coal transport to subsidize passenger prices. And even as Modi’s government sets highly aggressive targets for the growth of renewable energy, it has continued to declare in parallel that it will build more coal plants on a large scale. Roadblock #2 remains the credit risk of state-run off-takers. India’s distribution companies collectively lose hundreds of billions of dollars a year – despite the fact that new power sources are getting rapidly cheaper. Most would be bankrupt if not haphazardly propped up by governments. It’s a very large-scale problem: A new World Bank report titled, “In the Dark: How Much Do Power Sector Distortions Cost South Asia,” says India’s power sector inefficiencies cost the economy about 4% of GDP a year. And it’s a big problem for new renewables producers whose financial future depends on their off-takers being able to pay their bills. Roadblock #3 is predictability, along with India’s tradition of economic statism. One example is attempts to renegotiate contracts for political purposes, as seen above in the case of Andhra Pradesh. Another is the attempt to force government-owned firms into the picture. That until recently solar and wind auctions in India had functioned as they have everywhere else, with private sector firms being the bidders to provide new capacity, has run against some of India’s economic traditions. Especially in infrastructure, India’s history is one of state control. This June, India tried to turn the clock back in this direction with an auction for 1.8 GW of new solar capacity… which was only open to state-run firms. Though it seemed a shock to the organizers, it was not a shock to anyone else when the auction was undersubscribed by 2/3, drawing bids for just over half a Gigawatt. Very few state-owned companies (leaving aside partially state-owned exceptions such as Italy’s ENEL or France’s EDF) are nimble enough to keep moving down the production cost curve as aggressively as private producers have done this last decade.

These are pretty big roadblocks. In spite of the historic growth of solar capacity, many observers still believe coal will continue to dominate power in India (see Coal is King in India – and Will Remain So, from Brookings). India is the third-largest coal-fired generation producer globally, behind only China and the USA. Even at the impressive level of 80GW, renewables account for only 40% of the electricity generating capacity that coal-fired power does. And when generation factors are accounted for (meaning how often wind and solar plants are producing actual electricity), coal produces still 7 times the power that renewables do in the county. In 2015, India had plans for adding another 100 GW of coal-fired power generation over 5 years, which briefly became (as China’s announced programs shifted) the largest single-country pipeline in the world for new-build coal capacity. Nonetheless, the coal lobby has a big problem of its own. While formerly expensive solar is getting cheap, formerly cheap coal is getting expensive. Since 2007, bid prices to provide new coal-fired have essentially doubled, from as low as $0.036/KwH to $0.07 by 2013. The average price for coal-fired power on Indian exchanges in 2018 hovered around 7 cents/KwH. And while new renewable PPAs are price-fixed without inflation (meaning real prices on the contracts will actually decline over time), coal power is subject to inflation in the price of coal and other operating costs. Transport inefficiencies, disruptions in imported coal supply (as many coal mines cease to operate due to declining or unpredictable demand), and problems in the domestic mining sector have contributed to the rise, and decline in prices is unlikely. Some new coal plants are being commissioned (about 3 GW in 2018), though decommissioned older capacity means net coal generation is no longer growing. At least for now. This compares with net additions of thermal generation capacity of 20 GW annually from 2012-2016. And four years into the announced plan to add 100 GW of new coal-fired power from 2015 to 2020, only about 10% of this has been built. Plans still call for another 90 GW of new plants by 2026. Let’s see. Either way, the consequences of the next set of procurement decisions will be very large.

As the political power of coal and the economic gains of renewables square off, the future direction of energy in India may depend in large part on developments in energy storage (see Fortune India — Why Storage is the Next Big Thing). The issue with solar and wind is of course their intermittent nature. This is a manageable issue when intermittent power accounts for a small share of total electricity on a grid. Though that share is growing in India, the technical weaknesses of India’s transmission grids means problems occur at lower penetration levels of intermittent power, and Indians are naturally loath to see more country-wide blackouts as the monster experienced in 2012. Therefore the potential value of energy storage, enabling renewable energy to be released to the grid at times when wind is not blowing or sun is not shining, is even higher in India than in other places. As a forthcoming Infrastructure Ideas column will review, battery storage costs continue to plunge worldwide, and storage + renewables projects are beginning to replace even relatively cheap gas-fired capacity in the US and elsewhere. The Government issued its first large-scale tenders for storage in March 2019, and states are beginning to follow suit. The cabinet has approved a National Mission on Transformative Mobility and Battery Storage, which aims also to manufacture batteries on a large scale domestically. With India’s world-class engineering skills, one should expect energy storage built in India to be cost-competitive with storage projects in the US and Europe.

Compared to the ongoing energy transition in other countries, the above snapshot may seem to be missing a third player: natural gas-fired electricity generation. In the US, gas has played the largest role in recent energy shifts, and it is playing a big role in new capacity plans in China, the Middle East, and Latin America. It is also a key question mark for Bangladesh, Pakistan, and Indonesia. For India, there is less to talk about. Sure, India is building both gas import terminals and new gas-fired plans. There are offshore gas reserves, as there are for Bangladesh. But the scale, relative to the massive existing coal fleet and the massive renewable plans, is hardly worth talking about. It could become a bigger factor in the equation for India, but only if (a) the government allows prices for domestically produced gas to come closer to international prices, and (b) it also supports investment in transporting gas throughout the country.

Hydropower will also play some role, though the better hydro sites in India have already been developed, and recent dam-building history is filled with cost overruns, social displacement and construction problems, so it’s hard to see this as more than a minor actor. In Eastern India, imports of hydro-produced power from Bhutan, and maybe gas-fired power from Bangladesh, may play a regionally more important role. But on the large scale of large India, this is not where the main battle will play out.

Keep an eye on India. The development and living standards of hundreds of millions depend on continued economic progress there. As does the extent to which the planet will get hotter. High stakes. And a Top 3 coal power going against a Top 3 renewables plan – the stuff of Bollywood epics for years to come…

Asia’s Energy Transformation: Indonesia

On April 17, voters in Indonesia went to the polls and apparently re-elected President Joko Widodo (“Jokowi”) to a second term. Final results are due May 22. This election, and President Jokowi’s second term, if early results are confirmed, will have momentous consequences for infrastructure, energy and global climate.

This is the third in an Infrastructure Ideas series on the state of Asia’s Energy Transformation, following earlier reviews of the energy situation in Pakistan and in Bangladesh. Indonesia shares many commonalities with the other two countries: one of the ten most populated countries in the world (with over a quarter of a million people, Indonesia has the 4th largest population), facing energy high demand growth while running out of domestic fuel sources on which it has relied, and strongly considering a large-scale expansion in its coal-burning capacity to meet its energy needs. The energy choices Indonesia makes in the next few years will have major effects on the availability and cost of energy for Indonesians, and on global climate.

President Jokowi’s initial election, in 2014, was widely greeted as great news for infrastructure in Indonesia. His electoral platform stressed implementing reform programs needed to address Indonesia’s widespread and longstanding infrastructure problems, including beginning to bring in private capital and reduce reliance on Indonesia’s state-owned monopolies. His first term did not live up to expectations on this score: government bureaucracies and vested interests have been largely successful in limiting change. Yet needs continue to grow, and the same problems and choices will now face a second Jokowi administration.

Energy is the most critical battleground between the Indonesian old guard, clearly proponents of both maintaining state control and relying on Indonesia’s coal resources to meet energy needs, and reformers. Indonesia’s current electricity consumption and production are very low for a country of its size, with production capacity of about 60 Gigawatts (GW), slightly over half of which is coal based. The country’s “Electricity Supply Business Plan” (Known as RUPTL) calls for a near-doubling of capacity, to 115 GW by 2025, including from 25 to 35 GW of new coal-fired capacity. This places Indonesia among the five countries with the largest plans for new coal-fired power.

Indonesia’s coal resources are large, and unlike Pakistan and Bangladesh, the country has been developing and exploiting these at a large scale for decades. Indonesia ranks as the fifth largest coal producer globally (After China, the US, Australia and India), and is the world’s second biggest exporter of coal, after Australia. Those resources, however, are not unlimited: Price Waterhouse Coopers forecast that at planned utilization levels, the country’s coal resources would be exhausted by 2033.

Indonesia’s domestic energy resources are not at all limited to coal. The country was an oil exporter, until falling oil production turned into an importer. It has widespread hydropower potential, albeit complicated by land ownership and biodiversity considerations, and among the best geothermal energy potential of any country. About 9 GW of total electricity capacity today is renewable energy, mostly hydropower. The latest RUPTL projected a 300% increase in renewable energy capacity by 2025, to about 35 GW: 6 new GW of geothermal, 12 GW of large-scale Hydropower, and 8 GW of wind and solar (mostly wind). However, development of renewable energy has been largely stalled, due to a combination of land/biodiversity issues affecting hydro and geothermal projects, and of inability to get wind and solar-based power production off the ground. As a result, unlike many countries which are rapidly ramping up the share of energy use based on renewables – largely because these have become the cheapest alternatives, Indonesia has been stuck: not moving forward, and trying to do so mostly with coal-fired megaprojects. President Jokowi’s legacy in Indonesia will be largely determined whether in his second term he succeeds in getting the power sector unstuck, and in moving the country into exploiting low-cost wind and solar electricity, or whether he remains mired in Indonesia’s bureaucracy and vested interests.

Part of the roadblocks to Indonesia’s development of renewable resources is complicated: the land and biodiversity issues which are involved in many potential large-scale hydropower or geothermal projects will not easily be solved. But another part is simpler: country after country is taking advantage of the combination of free-falling technology costs in wind and solar and of auction mechanisms which force competition among the world’s still-growing number of producing companies. IRENA has stated that Indonesia has 47 GW of solar power potential. At least, better said, technically simple. And economically simple. The officially estimated cost of greenfield coal-fired generation may be lower in Indonesia than anywhere else ($0.05/ kilowatt hour), but those estimates like in many other places underestimate both coal transport costs and the impact of current disruptions in the coal market, without pricing in likely medium-term scarcity costs. Wind and solar prices are already on a par with the low-end of coal-based generation prices, and continue to fall.

Where large-scale development of wind and solar electricity in Indonesia is not simple is in the politics. The state-run power utility, PLN, combines a monopoly of transmission and distribution with being the by far largest producer of power. It is an artefact in a world where most countries have separated power generation from T&D responsibilities, and where most have increasingly turned to private capital for financing new generation capacity. And as both a competitor and the eventual buyer of wind and solar power from potential new producers, its enthusiasm for the wind and solar auctions which have triggered rapid growth in renewable capacity in many countries has been superficial. PLN would far rather build power plants itself – which means thermal or possibly hydropower power – than have others build them. Its reasons are a mix of classic bureaucratic inertia and self-interest, and of links to political interests and corruption. The reasons are not economic: the government has pumped between $3 and $4 billion annually into PLN in recent years to cover losses, and letting others finance power which will come at a lower cost to PLN would reduce those losses. A recent documentary released in Indonesia, which the government has tried hard to suppress, is named “Sexy Killers,” and highlights the links between the country’s coal industry, PLN and politicians. And as noted in a recent column by Bill McKibben, the potential for bribes in small-scale, decentralized wind and solar development is far smaller than it is where single mega-projects such as coal plants involved.

The past few months have seen somewhat of a stalemate. A few renewable projects have inched forward, as have a handful of natural gas-fired projects. But large-scale auctions for wind and solar have made no progress. The 2019 RUPTL, released in March, gave more verbal support to wind and hydropower, though without indicating it would take practical steps to bringing this closer to reality. A number of coal-fired plants planned in Java were reportedly suspended or cancelled, yet have re-appeared in the new policy document, and plans for solar are minimal. As noted in its review of the RUPTL, IEEFA called the statements about incorporating more renewables “a cut-and-paste planning exercise that does little to address fundamental problems with Indonesia’s over-reliance on coal-fired generation,” and stated that “Indonesia appears to have embraced what can best be described as a contrarian understanding of power trends with the decision to add less than 1 GW of solar over the next decade.”

On April 23, the arrest was announced of PLN’s CEO, Sofyan Basir, on charges of corruption related to a $900m coal-fired power plant. Unlike in the case of competitive public auctions in wind and solar, this coal project – Riau I – was awarded directly by a PLN subsidiary to a Singaporean company (arrests include one of the Singaporean company’s Board members). A sign of the tide turning? Indonesia’s energy and economic future hangs on the decisions that will be made by President Jokowi in his second term. As does a lot of carbon.

Asia’s Energy Transformation: Bangladesh

Asia’s Energy Transformation: Bangladesh

This is the second in an Infrastructure Ideas series looking at the way energy use is changing in Asia’s major economies, and the momentous choices facing policy-makers there today. Following the previous post covering Pakistan, this post features the world’s 8th most-populous nation – and the country with one of the five biggest project pipelines for new coal-fired generation: Bangladesh.

Bangladesh, known as East Pakistan from 1949 to 1972, is the most densely populated country in the world. Its energy profile has many similarities with that of Pakistan: both countries have enjoyed significant domestic natural gas resources, which played a major role in the development of the countries’ power grids – Bangladesh’s even more than Pakistan’s. Both Pakistan and Bangladesh are relatively low-income, and have among the lowest per capita levels of energy consumption in the world, and among the highest aspirational rates of growth for future energy consumption (Bangladesh’s growth rate has been in the 6-7% per annum range). Both countries subsidized consumption of domestic natural gas resources by keeping prices well below those prevailing internationally, and in part as a result reserves have been in decline and the ability to keep supplying gas-fired power plants is now in question. Both countries have largely untapped domestic coal reserves, generally of low quality, and coal enjoys a major role in future energy planning in both. Bangladesh and Pakistan are also late-comers to renewable energy (leaving aside Pakistan’s large hydropower capacity), with Pakistan having turned somewhat earlier to initial wind and solar power auctions.

Critically, both countries face a similar fork in their energy roads: build substantial new coal-fired electricity generation capacity – potentially making them among the 3 or 4 largest builders of new coal plants in the world – or encourage large-scale development of wind and solar power. The policy choices these two countries make will have major implications for their economies and people, as well as for global climate.

Thinking about growth is essential for understanding Bangladesh’s energy choices. The country’s total power generation capacity in 2015 was only 10 Gigawatts: more than 40 countries produce more electricity than this, while only 7 have more people than Bangladesh. And this is after roughly doubling Bangladesh’s capacity in the last decade. Bangladesh’s energy policy calls for raising power capacity by 2030 to 30 Gigawatts – triple the amount of electricity produced today. That’s growth! Bangladesh needs this much power, both to make up for its very low current consumption, and to support the high growth rate of its economy.

The issue for the country is that its current sources of energy cannot keep up with existing capacity, let alone this projected tripling. Today three-quarters of electricity in Bangladesh is supplied by natural gas, and Bangladesh is running out of it. Reserves are projected to be exhausted somewhere around 2029. Taking advantage of the changes in the natural gas industry – which in the last decade have made it an internationally traded commodity – Bangladesh has begun to invest in import terminals to bring external natural gas into the country. This makes plenty of sense as policy. However, the new imported gas is likely to be needed entirely to substitute for declining domestic gas sources, and is unlikely to be a major source of new capacity. Concerned as well as it is by today’s over-reliance on gas, Bangladesh’s government has focused on diversifying energy sources, which again makes sense. The question is how best to do this.

The Government of Bangladesh’s stated energy plans have for years focused on one principal answer: develop coal. While coal produces less than 500 MW of electricity in Bangladesh today, government projections have shown 2030 capacity as high as 20 Gigawatts – essentially all the planned increase in electricity production for the country. A 20 Gigawatt coal-fired pipeline would place Bangladesh – which is not in the 40 largest power producers today – 5th in the world in new coal-fired capacity: after only China, India, Vietnam and Indonesia. Bangladesh also has an important friend ready to support this policy choice: China. Bangladesh is a country of focus for China’s Belt and Road Initiative, and for Chinese financing generally. IEEFA has reported that Bangladesh has the most proposed coal-fired capacity and funding offered from China of any other country, totaling $7 billion for 14 Gigawatt of capacity (somewhere between 1/3 and ½ of total estimated costs for these projects).

Aside from China, support for coal-fired development draws from two other major sources: one, an outdated sense of economics, and two, perceived greater profitability. Bangladesh has been worrying about running out of natural gas and needing new energy sources for over a decade; during most of this time, coal has been accepted as the lowest-cost alternative, and still today many planners and onlookers think of it that way. Given the historical subsidy for domestic gas, electricity has been relatively cheap for Bangladeshis, and politicians are wary of new capacity forcing a sharp increase in prices. This sense of coal’s cheapness has fallen out of tune with today’s realities, but opinions have been slow to adapt. Coal-fired plants are also, universally, very large projects. Very large projects also, universally, give the greatest opportunities for large profits – regrettably often of the corrupt kind: it is much easier to get rich skimming off a mega-project than from dozens of small-to-mid-size renewable projects. Coal-based electricity also means large-scale domestic coal mining, with similar opportunities.

The big drawback for a coal-based plan for Bangladesh is economic reality. The perception of coal’s cheapness does not match its real costs (and here we only mean economic cost, without speaking of externalities like emissions). Developing Bangladesh’s coal mines will be very expensive, and very large greenfield projects also come with very large risks of delays and cost overruns. Transporting the coal to power plants can also be expensive. Importing coal also has high transport costs, as Bangladesh has virtually none of the needed import infrastructure it would require to feed several coal-fired plants. So coal feedstock is not likely to prove very cheap. A best case, looking costs in neighboring India, is that Bangladesh would produce coal-fired electricity at $0.08/ kilowatt hour – about the average retail price for electricity in the country today. More likely, with all the required ancillary infrastructure, large-scale coal power would cost at least $0.10/ kilowatt hour.

By contrast, auctions almost everywhere for wind and solar power are seeing prices at $0.07/kilowatt hour – even at $0.03/kilowatt hour in a handful of countries. Prices for generation continue to drop. Prices for energy storage, required to make intermittent wind and solar power available around-the-clock, are also dropping fast. The economics of wind and solar will increasingly be better than those of large-scale coal.

The problem for Bangladesh and its policy-makers today is that successful auctions for large-scale wind or solar power require significant planning. Planning is required not only for the new generation plants, but also for associated storage, and for upgrading the transmission grid to deal with large amounts of intermittent power supply. The planning is made trickier due to the lack of available land in Bangladesh, unlike in Pakistan. While Bangladesh has some excellent people resources in its ministries and administration, it doesn’t have a great many of them. One dead-end answer being looked at has been to have the government be the one to build solar plants: this has not worked anywhere outside China (excluding China, wind and solar generation is nearly 100% privately owned), including countries with much more public execution capacity than Bangladesh.
Still, this looks like a better set of problems to have to solve than those associated with coal.

These are big decisions for Bangladesh. Get it wrong and power prices will go up, with attendant political risks. Do nothing, and the economy will strangle for lack of power. Do coal, and the climate equation for everyone gets worse.

Lately, there are positive signs that Bangladesh is making the needed course correction. The Bangladesh Power Development Board’s 2016 Annual Report noted an expected eleven new coal-fired plants to be commissioned in the next five years. Its 2018 Report has this down to three, of which one – the Rampal project – has already seen repeated delays. Gas-fired projects are moving forward closer to the expected rate, with the GE and Mitsubishi joint venture with Bangladesh’s Summit Group – signed in July 2018 to establish five power plants along with gas import facilities – slated to become the country’s largest private investment on record. But wind and solar will be needed to fill the gap and help Bangladesh keep up with growth. Another country to watch for big decisions.