Asia’s Energy Transformation: China (Part 2)

November 2021

In our previous post, Infrastructure Ideas surveyed the state of the energy transition in China, the world’s largest consumer of energy and largest emitter of greenhouse gases, up through 2020. Today we pick up the country’s energy transition story for 2021, and look at it going forward.

As we saw in Part 1, China is on the one hand the home of world’s largest coal-fired electricity generation fleet, the home of probably 75%+ of plans for building more coal-fired plants, and the home of 14,000 Gigatons a year of GHG emissions – 30% of the world’s total. On the other hand, China is also the home of the world’s largest hydropower, wind and solar-powered generation fleets, and the energy and carbon-intensity of its economy have dropped about 40% since 2000. Its transition has been formed by a mix of directed government policies and market-driven shifts, and it entered 2021 simultaneously seeking to ensure availability of cheap and abundant power to support continued economic growth, and to be seen as a global leader on the fight against climate change.

2021: A turbulent year

The first eleven months of 2021 have been a rough ride for China’s energy sector. As global economic growth rebounded after the 2020 COVID-induced slowdown, the demand for China’s manufactured exports has jumped, leading in turn to sharp increases in demand for electricity from factories across the country. Demand for coal increased 11% in the first half of 2021, according to Foreign Policy. At the same time, political differences with Australia, China’s main source of imported coal, led the Government to block further imports from Australia. And officials looking to implement Xi Jinping’s directives to reduce emissions began to implement rules requiring provinces to reduce energy consumption. Natural gas shipments, which form a small but growing part of the country’s fuel sources, also became scarce and more expensive as demand for natural gas spiked across the world, in tandem with economic recovery and widespread disruptions in supply chains across different sectors. These factors came to a head in September and October, as demand for power steadily outstripped supply, and factories in many parts of the country began to run out of electricity. In order to avoid the domestic political costs of power shortages, officials have turned to re-opening coal mines and shuttered coal-fueled generation plants. As the New York Times reported in the week ahead of the Glasgow COP26 Summit, “The campaign has unleashed a flurry of activity in China’s coal country. Idled mines are restarting. Cottage-sized yellow backhoes are clearing and widening roads past terraced cornfields. Long columns of bright red freight trucks are converging on the region to haul the extra cargo.“

The ongoing energy crisis is laying bare fault lines among Chinese policy-makers. As Kelly Gallagher, a professor at the Fletcher School of Tufts University, notes: “There’s a tug of war right now. The central government is trying to limit coal production, and the local governments are doing the opposite. They want to restart plants or build new ones to get their local economies moving again post-pandemic.” Already in 2020, unusually sharp debate had arisen in China over how aggressively it should cut the use of coal. Prominent Chinese climate scientists and policy advisers want stricter emissions limits, including virtually no new coal power projects; powerful provinces, state companies and industry groups say China still needs to use large amounts of coal for electricity and industry for years to come (see the New York Time’s “China’s Climate Ambitions Collide with its Coal Addiction”).

The short-term crisis of 2021, however, sits against longer-term plans and objectives of China’s central government. More specifically, in a country led by a President who has arguably accumulated more authority than any President since Mao Tse Tung, it sits against declared objectives of President Xi Jinping. In April 2021, President Xi announced in a major policy speech that China’s emissions would peak by 2030, that China would increase the share of non-fossil fuels in its primary energy consumption to 25% by 2030 from just 6.8% in 2005 and take its total installed wind and solar capacity to 1,200 GW, and that China would achieve carbon neutrality by 2060. While full details of how China would achieve these objectives have not been announced by the Government, several building blocks in this direction have become visible:

China has begun to build a large network of ultra-high-voltage transmission lines linking the country’s interior, where wind and solar resources are plentiful and cheap, to demand hubs near the coast;
China’s National Energy Administration (NEA) has set a target to have renewables make up 50% of national installed capacity by 2025;
the NEA has further proposed that Chinese companies should be required to purchase 40% of their electricity needs from renewable sources by 2030;
electric utilities have been instructed to charge industrial customers up to five times as much when power is scarce, and generated mainly by coal, as when renewable energy is flooding into the grid;
provinces have been given directed incentives to make annual emissions reductions;
and the country has created the world’s largest carbon market (see “China’s New Carbon Market”).

China’s latest Five-Year Plan, a revered document in a country where state planning plays a large role, also charts several routes towards an increased investment shift to green tech.

A 1.5-degree roadmap

China’s energy path over the next few decades will in all likelihood be the single biggest determinant of how much the earth’s climate warms. It would be comforting to see a clear game plan for how the ambitious goals announced by the country’s leadership might be achieved – especially comforting in view of the country’s current scramble to increase coal use. As far as we know, the country does not yet have such a detailed plan. But, such a roadmap does exist.

We are informed by the International Energy Agency (IEA) that the Chinese government reached out to the IEA for input on its future energy transition. Who reached out to who is, for now, a secondary issue. What we have seen, as of last month, is the IEA’s release of “an energy sector roadmap to carbon neutrality in China,” which we can presume is being studied in Beijing. It is interesting that this IEA report has drawn limited visibility to date, as it is the most detailed and authoritative statement of how China might achieve its climate objectives, and how it might play its part – the biggest of all parts – in helping the world limit global warming to 1.5 degrees.

The IEA report’s roadmap has several key elements:

1. The first key finding from the IEA is that, to achieve carbon neutrality, China’s electricity consumption growth would have to greatly accelerate. This counter-intuitive finding, that China’s energy investment would have to rise 60% and electricity generation by 130% by 2060 in order to achieve carbon neutrality, is driven by the need to shift heating and other industrial processes from a reliance on liquid fuels and coal to electricity – which can “more easily” be made “clean.” Electricity demand also increases due to the development of hydrogen-based energy, which is power-intensive. Yet in spite of this increase in electricity consumption, power emissions reach a peak of 5.6 Gigatons by around 2025 and then fall to zero before 2055 and are marginally negative in 2060, helping to offset residual hard-to-abate emissions. The rate of decline in the carbon intensity of electricity – CO2 emissions per kilowatt hour generated – averages 3% per year in the 2020s, compared with 1% over the last decade.

2. The reliance of electricity generation on renewable energy sources in the IEA roadmap jumps from 23% in 2020 to 41% in 2030, and 83% by 2060. Solar power alone makes up 45% of the electricity mix by 2060, up from about 10% today. Between 2030 and 2060, 220 GW of PV and 57GW of wind are added to the grid annually, on average. Aside from wind and solar, four 1 GW nuclear reactors are launched every year (though the share of nuclear goes down to 10% from 5%), and hydropower grows 45% over the period.

3. Meanwhile the use of unabated coal generation drops to zero in 2045, with overall coal-fired generation capacity dropping from 1,030 to 360 GW, with 190 GW of that capacity having Carbon Capture and Storage capabilities, and 170 GW operating as standby reserve for the system.

It will no doubt take some time before China adopts, or not, the IEA plan, or more likely announces some variation of the roadmap. In the meantime, a big question would be: is there a viable 1.5-degree roadmap including China, and is the IEA plan a realistic version of such a roadmap?

Saying that pretty much everything in the IEA roadmap is unprecedented is correct, but not terribly illuminating. After all, much of what has happened in China’s energy transition to date has been unprecedented. Could China manage to add 220 GW of solar and 57 GW of wind power every year for the next three decades?

As we saw in the last post, China added some 72 GW of new wind power capacity in 2019 alone. The country has the manufacturing capacity to meet the roadmap target in wind, it has the wind potential, and it is investing today in building the transmission lines to connect windy areas with demand centers. It is worth noting that China’s command economy can push through transmission line investments more easily than can the United States, where local opposition is more likely to disrupt such plans. Aside from the policy incentive, wind power also has the advantage – a very big advantage – that it is far cheaper than coal-fired electricity, and will only get more so. China’s massive wind investments to date have not relied so much on this economic advantage, as the country’s yet limited use of competitive auctions for procuring renewables means that prices for new wind power in China remain perhaps double what they are in many places – including the US, where prices to buy power from new wind farms average less than 2 cents (US$0.02) per KwH – compared to coal-fired power prices in China of 5 to 8 cents. The wind targets in the IEA roadmap therefore look manageable.

The faster growth of solar generation in the roadmap will be more of a challenge. The 220 GW annual additions of solar called for by the IEA scenario are nearly equal to China’s current solar generation capacity. The entire United States, in 2020, installed less than 20 GW of new solar PV, less than 1/10^th of what the IEA calls for China to install annually. Here China’s manufacturing base will be sorely taxed to produce this volume of panels. The high share of intermittent generation in the roadmap, driven by solar growth, also implies the need for a giant leap in the manufacture and installation of energy storage capacity – even higher than that for solar, on a relative basis. Is it doable? Perhaps. China is already in construction on the world’s largest renewable energy project, a 100 GW wind and solar development in Kunming. This would be bigger than the combined wind and solar capacity of all of India, for one, and four times the size of China’s famous Three Gorges Dam. In fact, in a remarkable development, the company that created the dam, Three Gorges, has pivoted from being a hydropower developer to becoming one of the world’s largest wind and solar developers. The June 2021 IPO of its new affiliate, Three Gorges Renewables, became one of the most successful IPOs in history. If solar and storage are going to be the main engine of the roadmap for the next phase of China’s energy transition, then economics and employment will make the engine go. Much as is the case for wind, new solar power farms produce electricity cheaper, far cheaper, than coal plants – at least in most of the world. Slowly, this economic reality is arriving in China, as procurement shifts towards the auction-based competition which has been driving costs down everywhere else. At somewhere between a quarter to a half of the cost of coal power (without storage), or half the cost to even with storage, cheap solar power will be a huge economic boom for China’s consumers and manufacturers. Estimates indicate that by 2040, solar-plus-storage costs in China should range between $0.03-$0.085/KwH (depending on location) due to declines in battery costs and economies of scale. The development of wind, solar, and battery storage on the scale called for in the IEA roadmap will also create massive amounts of new jobs in China, as even their far smaller developments are creating around the world today. A challenge for China’s policy-makers, as is visible elsewhere, will be to sufficiently match the jobs displaced by reductions in the coal economy with those generated in the renewable economy.

Conclusion

Very ambitious targets for 2060 indeed in the IEA’s roadmap. You won’t have to wait until then, however, to see if China is on this kind of path, and have a clearer view as to how high global warming is headed. Most of the modelled 1.5-degree scenarios for China include rapid CO2 reductions over the next 5-10 years. Policies in place in 2020 would appear to have China’s emissions path more in line with a 3-degree global warming scenario. Yet even in the difficult energy crisis unfolding today in the country, more concrete steps towards the roadmap are being put in place. The two big hopes for lower emissions should be pinned on a combination of economics and global leadership aspirations. Both are those are pretty good incentives. Global Leadership on climate fits the narrative Chinese leaders have been trying to establish, and is certainly a topic which is much more welcome in global fora than discussions of internal Chinese political matters. Global leadership on climate also brings in its wake opportunities for China to lead in many industries of the future, with the prospect of underpinning continued strong economic growth for many years, and underpinning further growing global influence. Stay tuned…

Asia’s Energy Transformation — China (Part 1)

November 2021

This is the sixth of Infrastructure Ideas’ country-focused posts on the great Asia Energy Transformation underway, following previous reviews of the energy transition in each of Pakistan, Bangladesh, Indonesia, India and Vietnam. This will be a two-part review, with today’s post looking at China’s transition through 2020, and our next post looking at the events of 2021 and the path forward for China.

China is colossal, in terms of both energy and emissions. The country has the largest emissions of greenhouse gases (GHGs), the largest coal-fired generation fleet, the largest pipeline of still-planned new coal-fired plants, and… the largest wind-power fleet, and the largest solar generation capacity. In all these categories, second place to China is far, far distant. China’s energy mix is also in flux, and its choices matter far, far more than those of any other country. Where China’s energy mix heads over the next decade will go farther than anything else in determining how much warmer the world gets; as a recent report by the International Energy Agency (IEA) opens, “there is no path to limiting the global temperature rise to 1.5 degrees without China.”

China has been the top global emitter of GHG since 2006, and accounts for about 30% of the world’s total. The over 14,000 gigatons of GHG emissions in 2019 was a 25% increase ten-year since 2010. With some 4,500 gigatons, China’s power-generation sector is the biggest contributor to the country’s emissions, and accounts for about 10% of all global GHG emissions from all sources. A study by Carbon Tracker reported that, for the world to hit its goal of limiting global warming to 1.5 degrees, China would need to cut its CO2 emissions by more than 90% by 2050 – relative to its current trajectory. To do this, the study’s models show that China’s power sector would need to cut down its emissions by 66% by 2030 and achieve full decarbonization by 2050. A different study, by Climate Action Tracker, notes that while Xi Jinping’s April 2021 announcement on climate sets out a goal broadly consistent with the 1.5-degree target, current policies would rather imply that emissions levels from China are more consistent with a 3-degree global warming. Most recently, in September, the IEA issued a roadmap on how China could get from where its current policies would take its emissions, to Xi Jinping’s announced objective. The report notes that China’s energy sector has a path to deep cuts in emissions – though this path is not where current policies are heading, and it is very, very different than how the sector has evolved over the last decade. In this post we’ll take a look at that path to 1.5 degrees, and compare it to where China is and has been.

China’s Power Sector in 2020

Coal. In 2020, China consumed 7,620 terawatt-hours of electricity, an increase of 80% since 2010. Coal-fired power remains the mainstay of electricity generation in China, though its share has dropped from 78% of all generation in 2010 to 62% in 2020. In terms of capacity, coal makes up slightly over 50% of all electricity generation capacity, running naturally at higher rates of usage than intermittent sources such as wind and solar. China has some 4,000 coal-fired generation plants, and their installed capacity is eight times that of India’s. This coal-fired power fleet has grown enormously over the last decade, and is therefore quite young in technical terms. According to Global Energy Monitor (GEM), nearly half of China’s 1,047 Gigawatts of coal generation capacity has come on line since 2010. China now accounts for 51% of global coal-fired generation capacity. Again according to GEM, China has another 121 GW of coal-fired plants in the pipeline, 55% of global planned additional capacity around the world. This probably understates China’s share in potential coal-fired additions, as the announcements over the past year from Japan, Korea, and the China (see “Xi Jinping’s UN Coal Pledge”) that they would no longer finance coal-fired generation overseas – followed by the similar COP26 pledge made by several more high-income countries, means that at least half of all other planned capacity additions will be unfinanceable. China’s still-planned additions probably account for at least 75%, and possibly close to 90%, of the remaining global new coal pipeline. This said, there are some interesting aspects of this to consider. For one, China has actually cancelled 619 GW of at-one-time-planned coal plants: more than the rest of the world combined has built since 2010. And the building of new plants slowed significantly in 2019 and 2020. So it could be worse…

For the world’s climate, the million-dollar question is, where will coal in China go from here? Will the recent slowdown in building coal continue, and be followed by an era of decommissioning or retrofitting carbon capture on China’s coal fleet? 2021, as we’ll see in our next post, has provided a roller-coaster but not yet a clear answer.

Hydropower. When many people think of energy in China, the one image which comes to mind is the Three Gorges Dam, the largest in the world. Hydropower certainly has been an important part of Chinese planners’ approach to increasing energy supplies, and continues to be, generating more electricity than any source other than coal. Hydropower generation capacity in the country increased from 213 GW in 2010 to 375 GW in 2020. China is not only the world leader in hydropower capacity, but has more than triple the amount of this capacity than the next closest country, the United States. The share of hydropower in China’s generation mix has been relatively stable over the last decade, at between 16-19% of total generation. The share of hydropower in new power capacity additions has fluctuated during this period, depending on the timing of opening of new large dams. The 22.5 GW Baihetan dam hydropower facility, opened last year on a tributary of the Yangtze, is the world’s second largest hydropower scheme in operation, after the Three Gorges dam.

Further growth in hydropower would be an important ingredient in a decarbonization strategy for China, especially as it provides baseload power to replace coal much more easily than wind and solar do.

Nuclear. China is one of the very few countries in the world still rapidly adding nuclear power generation capacity. David Sandalow, of the Columbia Center for Energy Policy, reported that in 2018, seven of the world’s nine nuclear power plants that connected to the grid for the first time were in China. Today just under 5% of China’s electricity generation comes from nuclear energy, with reported generation capacity at about 49 GW from 36 operational reactors. That volume is expected to quadruple over the coming decade, according to China’s National Energy Administration, to some 200 GW by 2030, and then grow another 70% to 340 GW by 2050 (see figure below). Like hydropower, further growth in nuclear capacity would be an important ingredient in a decarbonization strategy for China, especially for baseload power supply.

Natural gas. When the combination of new drilling technologies and the development of cheaper, commoditized shipping containers for natural gas emerged around 2010, global trading in natural gas began to grow exponentially. No country was as eager to benefit from this emerging trade boom than China, which announced a target of 110 GW of electricity generation from natural gas by 2020. While that target was not met, the 97 GW of natural gas-fired capacity now installed in China represents a dramatic increase, accounting for some 3% of total power production. In the short-term, China sees natural gas as a critical component of its strategy to reduce dependency on coal, especially for baseload power. The 14^th Five-Year Plan calls for adding some 40-50 GW of additional natural gas-fired capacity by 2025. In the longer-term natural gas-fired plants, much like coal, would need to be either decommissioned or abated for China to achieve its stated zero-emission goal by 2060.

Wind Power. The year 2020 was a landmark for wind power in China. The country added a whopping 71.7 GW of wind power capacity last year, the most ever and nearly triple 2019’s levels, according to data released by the National Energy Administration (NEA). China’s 2020 figure is ahead of the 60.4 GW of new wind capacity added globally in 2019, according to data from the Global Wind Energy Council. It was also a landmark in that 2020 saw, for the first time, wind being the single largest source of new electricity generation capacity in China (see graphic below). Among recent noteworthy wind developments is China’s State Power Investment Corporation Ulanqab Wind Power Base, approved in 2018, which would be spread across a 3,800km2 area in the north of China, close to the border with Mongolia. It would be the largest onshore wind farm in the world. The 6 GW, $6.8 billion project would deliver to the Beijing-Tianjin-Hebei power market to the south, without subsidies. Wind now accounts for over 10% of China’s total generation capacity, and at slightly over 300 GW, is some 30% higher than the collective installed wind generation of the European Union, and more than double that of the United States. Going forward, any decarbonization strategy for China and its energy sector will need to rely very heavily on wind. Wind is cheap and it is plentiful in China, and there is enormous growth potential, but for it to be realized China will need to address its transmission capacity shortages.

Solar Power. It can be hard to remember, but once upon a time China was well behind the rest of the world in solar power. In 2009, China accounted for a tiny 2% of global installations, as Europe began to scale up its installations. Just eight years later, China claimed more than half of the market, installing over 50 GW of solar in 2017. This level had an element of artificiality to it, as China in 2017 was still using the pricing mechanism for new solar farms that most of the rest of the world had already abandoned: feed-in-pricing. Feed-in-tariffs mean that the buyer (in this case China’s state-run distribution companies) agrees to pay a pre-announced price to anyone able to deliver solar power by a certain time: with costs of installing solar power plunging, this created a situation where installers saw larger profit potential than they did in other markets, where they were forced by auctions to compete against each other. China caught on eventually and began to move towards auction-based procurement in 2018, which had the effect of reducing installations of new solar in 2018 and 2019, but also the effect of significantly reducing the prices distribution companies now had to pay for new solar. At the end of 2017, the average cost of solar in China was $0.11/KwH, substantially higher than the 2 to 5 cents being paid for new solar in most markets. The market has now re-adjusted and new solar installations bounced back up in 2020, from 30 to almost 50 GW. Prices for new solar contracts are capped at $0.08/KwH, and have seen drops to as low as $0.03. Given abundance of land and sun, and the ability to build very large-scale projects, we would expect these prices to drop further, to the levels seen in the Gulf, of between 1-2 cents per kilowatt-hour.

At the end of 2020, China had 252 GW of solar power generation capacity, up from a 2010 level of… One GW (see figure below). The country with the second largest solar electricity fleet, the United States, passed the 100 GW installed mark earlier in 2021. China’s 252 GW accounts for just under 10% of China’s installed power generation capacity, and accounts for just under one half of the entire world’s solar generation capacity: essentially all of this has been built in the last decade. Going forward, solar is expected to continue, and hopefully even further accelerate, its remarkable growth in China. Combined with energy storage, it is projected – in all decarbonization models for China – to become the country’s number one source of electricity. Can it do so? That has to be the second of the million-dollar questions for the trajectory of global warming.

Recent Changes in China’s power markets

As with many things in China, energy management in China is a hybrid of government decision-making and market mechanisms. Prices for power generators have become increasingly freed, while prices to consumers are allowed to go down, but rarely up. As noted above, China used administrative mechanisms to promote the growth of wind and then solar generation, and then moved (sometimes slowly) to the competitive procurement of both through auctions. The move to competitive auctions for solar was initially unsuccessful, with most 2018 bids coming from state-owned companies only; private firms were wary of the combination of sharply lower prices from competition, while uncertainties about offtake risks remained. The government then had to complement the introduction of auctions with a series of incentives, including that all renewable power from new entrants would be purchased under 20-year contracts, with guaranteed grid connections and reduced transmission fees. State planning continues to matter a lot, as do political pronouncements.

China’s hybrid approach to sector management has had unintended consequences at several junctures. One unusual situation dates back to late 20^th century reforms. As China’s economic growth accelerated and continued, energy supply emerged as a major issue. This prompted the government to adopt a number of policies encouraging the building of new coal plants, including price mechanisms essentially guaranteeing their profitability, but with central government approval always required. That central approval began to lead to years-long delays, and in 2014 China allowed provincial governments to approve power plants on their own. Local governments were under enormous political pressure to increase the economic productivity in their region and saw new coal plants as a great shortcut: as a consequence, in 2015 the capacity of newly approved coal plants in China tripled. The Federal government backtracked two years later, but the number of plants launched in 2015 and 2016 (along with the steep increases in supply from other sources) led to oversupply of power through 2020.

Power oversupply in recent years has had further unintended consequences. In 2019 it was announced that over half of the power plants operated by China’s Big Five state-owned utilities were running at a loss, idle up to 50% of the time, and that the government planned for up to 15% of the country’s coal capacity to shut. Meanwhile curtailment (power offered by wind and solar producers but not accepted by transmission companies) emerged as a major issue for renewable energy producers. Curtailment also stems from geographic issues: although major solar and wind power installations in China’s more far-flung provinces can produce large amounts of renewable energy, a lack of high-voltage transmission infrastructure means that a sizeable percentage of that goes unused. Curtailment reached a high of 17% in 2016, in part because transmission companies preferred to use steady (though polluting) coal power rather than intermittently available renewable power. This created major – unintended – disincentives for renewable energy providers. Another directive in 2018 now guarantees new solar generators that state-owned transmission companies will buy their electricity. Government planners now need to direct investment – and that would be public sector investment – to building the transmission lines that can utilize that power. Along with transmission, storage will also be needed. China’s State Grid Corp announced in late 2020 that it will invest US$5.7 to build pumped hydro storage plants in an effort to ease stranded power systems, with a combined capacity of 6 GW, giving it a total of 30 GW of storage under construction.

Prices have also begun to become more important in China’s power sector. Part of the 2014-2015 reforms proclaimed that the market should give investors price signals on when and what to build. Progress on implementation has however been slow, and less than 30% of electricity produced in China was sold via deregulated mechanisms in 2019. Not surprisingly, with falling wind and solar costs, where electricity has been sold at deregulated rates, prices have dropped.

The State of Play Entering 2021

At the end of 2020, China stood squarely in the middle of the big global questions on climate change. One the one hand, its emissions dwarf those of other countries, coal dominates the energy sector and the building of new coal plants boomed over the last decade. Local and state governments in China, much like in many other countries, are often strong defenders of coal, fearing local economic decline and unrest if its use falls. On the other hand, China has become the world’s leading builder of non-emitting generating plants using wind, solar, hydropower and nuclear. In spite of the boom in new coal plants of the 2010s, coal has lost over 15% of its market share to wind and solar. China’s central leadership, most importantly Xi Jinping personally, has made clear its desire to be seen as an international leader on helping tackle climate change.

China’s mix of directed policy and use of markets has not always produced the intended results, at least in the short term. 2021, as we will review in the next Infrastructure Ideas post, has seen its share of further unintended results. Next up: what does the path to China’s stated emission targets look like?

Index to Previous Infrastructure Ideas Posts on Energy Markets

Silver Linings

Silver Linings: the COVID-19 crisis and infrastructure
May 2020

The COVID-19 epidemic has transformed pretty much all aspects of life over the past three months. Our previous Infrastructure Ideas column, written in the early days of the pandemic, outlined some of the possible effects of COVID-19 on the world of infrastructure. As is the case in so many areas, the implications were depressing. It is also apparent that positive news are in great need – and not based on distorted data and magical thinking, as can be seen coming from some quarters. Today’s column looks then at some silver linings for infrastructure in the pandemic era – and there are some!

We’ll start with the two most obvious “winners” from the crisis: logistics, and emissions reductions.

1) New and expanded logistics opportunities. As can be readily seen on any highway or city street, the amount of goods being delivered to homes through (generally) online orders has skyrocketed in 2020. The world’s biggest retailer, Walmart, has reported a 74% increase in e-commerce sales for the last quarter. Volumes have grown so sharply that even logistics giants are having difficulties keeping up: FedEx has asked several of its major store clients to slow or limit home delivery sales in order for FedEx to be able to manage shipping logistics. Amazon, possibly the biggest winner of all, announced back in March that it would be hiring for as many as 100,000 new positions, mainly in warehouse handling, and reported a 26% increase in quarterly sales – an impressive feat for a company with already over $200 billion annual revenue. And providers of logistics software and supporting services are also thriving.

The jump in demand for infrastructure logistics driven by e-commerce and home delivery services is broad-based and likely to remain with us. As Coronavirus infections continue to spread into new areas, demand is growing in virtually all geographies. An example is the three-year old Colombian company Liftit, recipient of an investment from the IFC. Liftit provides a technological platform that connects truck drivers with companies that need cargo delivered (similar to a ride-hailing app), and has already expanded beyond Colombia. The matching of large customers with truck fleets is a crucial link in the supply chains, especially in regions where the majority of drivers are independents (See more on Liftit here). In Pakistan, a similar app-based service connecting people and goods via motorbikes in major cities, Bykea, is getting a far-higher profile through the delivery of food parcels for thousands of people during the crisis. Bykea uses smartphones, a call center comprised mostly of women working from home, and a network of 30,000 motorbike driver-partners. In Africa, the use of drones for logistics has gotten a major COVID-related boost from the demand for transporting test samples to labs. US startup Zipline has launched operations for its pilotless flying vehicles in Ghana and Rwanda, also using them to ship protective equipment, vaccines, drugs and other supplies. These kind of advances, combined with changes in consumer demand (buyers who discover convenience which they had not tested previously, and/or those who remain wary of crowded retail shopping situations in the future for health reasons), will continue to fuel logistics growth well into the future. And an analysis by the Brookings Institute (Could COVID-19 help logistics?) shows some of the labor-related benefits of logistics jobs indicates that these jobs often carry good training opportunities with transferrable skillsets, and potentially higher pay relative to low formal educational barriers to entry.

2) Emissions reductions. An international study of global carbon emissions found that daily emissions declined 17% between January and early April, over 1,000 metric tons compared to average levels in 2019, and could decline anywhere between 4.4% to 8% by end 2020. That would mark the largest annual decrease in carbon emissions since WW II. Carbon reductions are primarily driven by fewer people driving — surface transport activity levels dropped 50% by the end of April. This was equal to (50%) the fall in the amount of gasoline supplied in the US—a close measurement of direct consumption— over the two-week period ending April 3. With all those cars now sequestered in garages, air quality around the world has gone through the roof. As reported in Wired, researchers at Columbia University calculated that carbon monoxide emissions in New York City, mostly coming from vehicles, fell by 50% in March. Another positive side effect of this is on public health: research from the Harvard School of Public Health has shown that air pollution is associated with higher Covid-19 death rates, even small increases in long-term exposure to fine particulate matter leads to significantly higher mortality. Chances are not great that emissions will stay on this path post-crisis, but for now this piece of news is good for the climate.

3) Acceleration of the energy transition. Aside from the two obvious winners above, there are other interesting trends flowing more under the radar. One is on energy transition. While it is likely that energy use will rebound sharply after the pandemic, its carbon intensity should be lower. Of particular interest is that while the coronavirus lockdown will cause the biggest drop in energy demand in history, it looks like renewables will manage to increase output through the crisis. The International Energy Agency (IEA) says that demand is likely to fall 6% in 2020, with rich countries showing a steeper decline, the U.S. falling 9% and the European Union losing 11%. Global oil demand is poised to slump by about 9%, coal demand is falling about 8%, and natural gas about 5%. Yet the IEA expects production of wind and solar to grow in 2020. In the first week of April, it was widely reported that wind and solar had produced more electricity in the US than coal did for two months in a row, for the first time on record. A Wood Mackenzie analyst, Matthew Preston, notes that coal is now more expensive in most of the US than natural gas, wind or solar energy: “Just about everything that can go wrong, has gone wrong for the coal industry.” More banks, including HSBC in April, have announced the cessation of coal financing; HSBC’s announcement closed previous loopholes for coal plants in Bangladesh, Indonesia and Vietnam, and included a Vietnamese project for which it was the global coordinator. HSBC had reportedly financed $8 billion of new coal plants over the past three years. While oil and gas prices have fallen sharply in 2020 to date, there are signs of supply reductions and cost increases on the post-crisis horizon. Moody’s had announced already in late 2019 that 91% of all US third-quarter defaulted corporate debt was due to oil and gas companies. As wind and solar prices continue to fall (see below), coal’s lack of competitiveness will grow, while gas will also have an increasingly harder time competing on costs against renewables. Expect that projections for renewables’ share of the energy mix in future years begin to tick up.

4) Technology continues to move forward. The single brightest development in infrastructure for the past decade has been that energy has been getting cheaper around the world, driven initially by the increased supply of natural gas enabled by new imaging and drilling technology, and in more recent years by the continued technology-led plunge in wind and solar costs. While these gains have fallen out of the headlines during the COVID-19 pandemic, they have been continuing.

In late April, yet another global record-low solar price was achieved. And it was achieved for the world’s largest solar project. Abu Dhabi announced that the winning bid for its Al Dhafra project – which at 2 Gigawatts will be the largest single-site solar energy project in the world – came in at a stunning 1.35 US cents per kilowatt-hour. A consortium of EDF and JinkoSolar was the winner. This breaks the previous record of 1.6 cents/Kwh from January in Qatar, and 1.7 cents/Kwh from November 2019 in Dubai. An even larger project, on multiple sites within one solar park, Bhadla solar power park in Rajasthan, India, became fully operational in March. The park has 2.25 GW of now operating solar capacity. The solar park saw multiple record-low tariffs (down to US 3.8 cents/Kwh) during some highly competitive auctions. More and more wind and solar capacity is also being developed in “hybrid” projects including battery storage. According to the US Energy Information Administration there are already 4.6 GW of wind, gas, oil and photovoltaic power plants co-located with batteries in the U.S., with another 14.7 GW in the immediate development pipeline and 69 GW in the longer-term interconnection queues of regional power markets. In the interconnection queues, a quarter of all proposed solar projects are combined with batteries, and in bellwether California, almost two-thirds of solar projects are proposed as hybrids. Power-purchase agreement prices for hybrid power plants are continuing to plummet, with declining costs for wind, solar and batteries as these technologies mature. And on the newer-technology end, in early May Minnesota utility Great River Energy confirmed it will deploy a one MW battery with 150 hours capacity – completed unprecedented for the energy industry. The battery, an “aqueous air” battery system from Form Energy, is due online late 2023, and increases contracted battery storage records by more than 20 times. This is the first announced deal that will take the technology out of the lab and deploy it in a full-scale power plant context. In conjunction with this, Great River Energy, the second-largest power supplier in Minnesota, announced plans to phase out coal power. The arrival of long-duration storage will be another major turning point for energy systems worldwide.

5) And some miscellany. While not rising to the level of the previous four positives for infrastructure, there are a handful of other interesting developments for infrastructure investors and users to keep an eye on during the pandemic. One is around highly depressed air travel: while airlines seem to be doing a reasonably good job keeping flying as virus-free as possible, conditions at airports have potential travelers very concerned about returning to flying. This may well lead to a push for building new airport terminals of very different designs than current terminals; “Future-proofing” has become an “in” term for airport designers, with both health screening facilities and more spaces to enable social distancing than today’s terminals, which often seek to maximize density. This may entail terminals built with steel instead of concrete to increase flexibility, as well as very different uses of space. Investors may see an unexpected area to put capital into infrastructure here. A second area is expanded broadband access. As more schools across more jurisdictions try to implement distance learning, the importance of accessible internet where it is today not available has shot up the list of political priorities. Close to 200 countries have announced or implemented school closures in 2020, with the majority seeking to implement online courses, and quality of internet access has become a major issue. We can expect this area to draw on a far greater portion of public infrastructure spending – possibly as Public-Private Partnerships – as a result of the crisis. A third and related area stems from the exponential increase in online courses driven by the crisis and school closures. This, combined with improved rural broadband access, could become a major factor in expanded technical training in developing countries. Lack of trained staff is a significant bottleneck for rail, logistics, and other infrastructure services in many countries. Fourth, bicycle-sharing and e-bike programs look like they may gain from the crisis. While initially bike-sharing plunged from concerns over potential virus spread, they have strongly rebounded in many places. Bicycle ridership has soared generally, as public transit is viewed as a source of virus exposure risk and some cities close streets to cars to enable more socially-distanced walking (and biking), and sterilizing equipment has emerged as easier for shared bicycles than for shared cars. Miami is one place that has also launched expanded e-bike delivery services during the pandemic. And fifth, the virus may stimulate greater attention to urban sanitation generally, as urban areas have been disproportionately affected by COVID-19. Perhaps we may at long last see an uptick in public infrastructure spending in sanitation, or greater willingness to consider Public-Private-Partnerships in the area.

These are trying times for everyone, including in infrastructure. But at least there are silver linings. We all need positives some of the time. And at some stage, the crisis will be over!

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.

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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.

Infrastructure in 2020: Ten Predictions

Infrastructure in 2020: ten predictions
January 2020

1. Wind and solar keep growing.

Growth in global renewable energy investment in 2018 and 2019 has been akin to the Sherlock Holmes tale of the curious incident of the dog that didn’t bark – there hasn’t been any. After a down year in 2018, global renewable energy investment stayed essentially flat at $282B in 2019, according to Bloomberg New Energy Finance (though still more than double BNEF’s estimate of investment in fossil fuel-based generation). Look for numbers to head back up in 2020, on the back of renewables’ cost advantages. In the US, the EIA forecast last week that wind and solar will make up three-quarters of new capacity additions in 2020, breaking previous records of annual capacity additions. The big variable for the coming year will be the largest renewable market in the world, China. The missing global renewable growth would have been there in 2018 and 2019 were it not for declines in China, whose $83B 2019 investment level was down for a second straight year, primarily in solar which is down 2/3 since its 2017 peak. As China transitions away from its Feed-in-Tariff mechanism for domestic solar generation towards competitive auctions, Infrastructure Ideas expects prices for new capacity to tumble, as they have everywhere else that auctions have taken hold, and growth in solar installations to resume in response. For Emerging Markets other than China and India, wind and solar investment rose 22% to a record $47.5 billion. In 2020, look for $300B in investment, a record 200 GW in new wind and solar capacity, and renewables as a share of net new generating capacity added worldwide to cross 70% for this first time.

2. Offshore wind is the new big thing

It looked like a curiosity for many years, but offshore wind is now breaking into the mainstream of electricity generation. Only five years ago, offered prices for offshore tended around $0.15-0.20 a kilowatt-hour, well-above the price for competing sources. But larger and more efficient turbines, bigger projects, access to better offshore wind resources, and more developed supply chains have been driving prices down. In September 2019, the UK saw bids for offshore generation at under $0.05/KwH, and now offshore is able to compete without subsidies in many markets. Bloomberg reports offshore wind financings in 2019 came close to a whopping $30 billion. Tenders are planned in many countries, and are spreading beyond initial markets of Europe, the US and China. Vietnam is looking at what could become the world’s largest offshore wind farm with a capacity of 3,400 MW. Look for many offshore wind headlines in 2020.

3. Challenges mount for power grids and utilities

Grid operators will continue to see a ramp-up of challenges associated with the energy transition in 2020. In developed markets, these challenges include continued switching to lower-cost generation sources, transmission, integrating storage, and integrating growing numbers of electric vehicles. The average EV traveling 100 miles uses as much power as the average US home does daily. California projects that EV’s will use over 5% of the state’s generation capacity by 2030. In developing markets with technically weaker grids, dealing with intermittency will be a bigger challenge, as well as integrating distributed generation and storage. Emerging Market cities may also create new demands as they start adopting electric buses in large volumes, the way we’ve seen in China. Large EV bus fleets will put significant pressure on charging infrastructure resources, while also offering potential storage solutions for urban utilities, especially as Vehicle-to-grid technology, or V2G, becomes more available. Look in 2020 for larger transmission investments in developed markets, and increasing concern in Emerging Markets – particularly those with state-owned grids – about how to modernize grids.

4. Non-lithium batteries get serious

As recently headlined in the Economist, Generating clean power is now relatively straightforward. Storing it is far trickier. Total investment in storage in 2019 came to around $5B, 99% in lithium-ion batteries. While this has been a major success, grids will need complements to lithium-ion technology soon. Though the cost of lithium-ion batteries is falling quickly, longer-term storage is likely beyond its practical capacity. Capacity to keep growing with solar and wind is also a question: the Institute for Sustainable Futures states that a world run fully on renewables would require 280% of the world’s lithium reserves, while concerns over sustainable sourcing of cobalt remain. Companies focused on longer-duration storage alternatives saw a major influx of investment in 2019, led by Energy Vault $110 million funding round, the single largest equity investment in a stationary storage company, according to Wood Mackenzie. Highview Power signed the first liquid air storage offtake deal, for 50MW in Vermont in December 2019. While 2020 project announcements with non-lithium batteries will remain small, look for them to make big headlines. And look for them to spread faster into smaller, low-income developing countries. The economics are more favorable in remote or island grids, where imported diesel creates a much-easier benchmark for storage to beat on price. Canada’s e-Zn targets remote communities that stand to benefit by offsetting diesel generator usage. NantEnergy, using zinc-air batteries has installed some 3,000 microgrids.

5. Green House Gas emissions: alarm keeps climbing, but no global agreements yet

One of our safest predictions. New studies and projections will continue to show climate change having a larger impact sooner than their predecessors. And politics, centered but not limited to the US, will again prevent significant concerted action to reduce emissions. The 2019 Madrid Summit was a glaring display of the stand-off. The only possible change for even 2021 here is the November election in the US.

6. Emissions-free city zones multiply

Though no global climate agreements are on the horizon, there is much climate policy activity at the local and national level: one big example is emissions-free city zones. This month, Barcelona opened southern Europe’s biggest low-emissions zone, covering the entire metropolitan area. Petrol-driven cars bought before 2000 and diesels older than 2006 are banned and face fines of up to €500 each time they enter the zone, which is monitored by 150 cameras. The new Spanish government is said to be planning low emission zones for all towns with over 50,000 residents. Whether driven by national or municipal authorities, we can expect to see such initiatives multiply rapidly, driven both by concerns over global climate inaction and over local air quality. Such zones now create opportunities for carmakers, though one can also expect to see EVs increasingly favored by such mandates, tilting the new opportunities towards EVs – and providers of EV infrastructure.

7. Unilateral “100% renewables” commitments multiply

Between frustration at the lack of global progress on reducing emissions, and the prospect of increasingly cost-competitive renewables and storage resources, a growing number of US states and utilities are setting targets for reliance on 100% clean energy. Thirteen US states, along with Puerto Rico and the District of Columbia, have now set 100% clean energy targets. Another four large states have announced plans to do so. Half-a-dozen large private-sector utilities have also committed to 100% clean energy targets, including famously coal-intensive Duke Energy. These mandates will continue to open new opportunities for renewable energy and storage providers, and importantly will likely offer less price-sensitive demand for longer-duration storage providers. The mandates will also start to impinge increasingly on natural gas demand for generation, and risk beginning to strand fossil-fuel generation capacity ahead of technical end-of-life timetables.

8. Financing premiums appear for climate risks

A big piece of news in the finance world last week was Blackrock’s announcement it would put in place a coal-exclusion policy. But even with Blackrock’s heft — it is the world’s largest investor in coal – this by itself is not a huge game-changer: not much new coal is going up in Blackrock’s geographies. Expect the bigger news in 2020 for infrastructure financing to instead be the appearance of the higher financial costs related to climate risks. In many ways it is shocking this has not happened yet, though a good piece of reporting from the New York Times last September pointed a finger at a big reason for the US. The Times reported that US banks are shielding themselves from climate change at taxpayers’ expense by shifting riskier mortgages — such as those in coastal areas — off their books and over to the federal government. Regulations governing Fannie Mae and Freddie Mac do not let them factor the added risk from natural disasters into their pricing, which means banks can offload mortgages in vulnerable areas without financial penalty. That cannot last without soon bankrupting the two biggest pieces of the US mortgage system (although it would be consistent for the Trump administration to prefer that option). The broader insurance industry is also suffering. According to Swiss Re, 2017 and 2018 were for insurers the most-expensive two-year period of natural catastrophes on record, most of them related to global warming. 2018’s most expensive insurance payout anywhere in the world was for the California Camp Fire. Fortune noted that new research shows that the wildfires of 2017 and 2018 alone wiped out a full quarter-century of the insurance industry’s profits. Unlike Fannie Mae and Freddie Mac, private insurance companies can react, and they will have to charge more to stay afloat. Expect 2020 to be the year that insurance prices begin to factor in climate-related catastrophe risks in a big way, and for that to begin flowing through to financing costs.

9. Delivery vehicles become the new EV focus

Electric car and bus sales volumes continue to grow, but expect electric vans to get a lot of the attention in 2020. Already in September 2019, Amazon placed a massive order for over 100,000 electric delivery vans – worth about $6B. The continued rocketing growth of the e-commerce delivery business, and the frequent use of diesel vehicles for delivery, make for an attractive and fast-growing market for electric vans. As noted by Wired, urban deliveries don’t require all that much range. Routes are predictable and plannable, and because the vehicles return at the end of every shift to a depot, recharging them is a breeze. Add the concerns of many cities about transport emissions, as noted above, and the attraction of the new market segment is easy to see. Now 2020 has started with a $110 million investment for Arrival, a UK start-up making electric delivery vans, from the combination of Hyundai and Kia. Arrival promises that its vehicles will be cheaper than their traditional, diesel-powered competitors, even without further declines in battery prices. Interestingly Arrival’s business model will also facilitate more rapid expansion to Emerging Markets than for makers of other EVs. Rather than building a huge new production plant, Arrival will work from “microfactories” that make only 10,000 or so vehicles a year, but sit closer to where their customers are, and making geographic expansion simple. Look for major changes in the logistics business in emerging country cities to flow from this soon.

10. More alarms over hacking of infrastructure

Many new opportunities are opening for infrastructure investment. Yet risks are growing as well. The hacking of Ukrainian energy company Burisma late in 2019 by the Russian military was clearly politically motivated. Hacking capabilities continue to grow far faster than defenses. Look for more widely-publicized attacks on infrastructure assets in 2020.

Airports, Ports and Climate Change (II)

Airports, Ports, and Climate Change (part 2)
December 2019

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This is the second in a two-part Infrastructure Ideas series on the effects of climate change on infrastructure transport facilities, following part 1 on airports. This post will survey climate change impacts on ports around the world.

Over 3700 maritime ports and their supply chains enable global and local commerce, helping the over 90% of the world’s freight that moves by sea. Ships make on average some 3 million landings a year at ports around the world. One study found that ports and ships account for as much as one-quarter of the GDP of the United States, contributing over $5 trillion to the US economy alone. All of these ports are, by definition (leaving out “dry ports” which have their own importance in logistics chains) located by water. As climate change accelerates, and waters rise, all of these ports will be affected by a range of consequences, some of them expensive.

The EU’s Joint Research Center projects that by 2030 64% of all seaports are expected to be inundated by sea level rise, due to the combined effects of tides, waves, and storm surges. The number of ports that face the risk of inundation in 2080 is expected to increase further by 80% to 2080. While various climate change projections may have considerable uncertainty, depending on the combination of how much higher carbon dioxide atmospheric concentrations get (uncertain because possible future emission trajectories are all over the place) and of feedback loops (on which key pieces of the science remain untested), two things are very clear: (1) sea levels will rise, and (2) they will rise more in some places than others. In Europe, it is forecast that the North Sea (where 15% of total world cargo is handled), the Western part of the Baltic Sea, and parts of the British and French Atlantic coasts will see double the sea level rise of most of the rest Europe’s coastline. In the Black Sea and the Mediterranean, impacts from extreme high sea level are expected to be significantly milder, but also to occur more frequently. One analysis projects that once-in-a-century “extreme sea levels” will on average occur approximately every 11 years by 2050, and every 3 and 1 year by 2100 under more extreme warming scenarios. The analysis adds that “some regions are projected to experience an even higher increase in the frequency of occurrence of extreme events, most notably along the Mediterranean and the Black Sea, where the present day 100-year ESL is projected to occur several times a year.”

One might superficially think that rising water levels would, for seaports, be a matter of indifference, or even a plus. As opposed to airports, where airplanes affected by inundation become useless, ports are home to ships which float on top of the water – no matter how high the water is. Dredging might become less of a concern in some ports, and other ports may become less dependent on high tides for larger cargo ships to enter. But while it is no doubt true that climate change impacts will be more severe for airports than for ports, they will not be absent for port owners and operators. A 2011 case study published by the International Finance Corporation, on a port in Colombia, summarized well the issues, of which the two biggest are the storage and movement of goods, and multimodal connectivity inland from the port. Ships can keep floating as the waters rise, but containers of goods cannot. Spoilage risk can be expected to affect revenues in particular for ports handling grains and other perishables. The fairly small number of transshipment ports may not worry too much about inland connectivity, but the large majority of operators will be need to be concerned about impacts of high waters on infrastructure which they do not control – roads, and sometimes rail lines – in and out of the port to other parts of their region. A review of risks to Long Beach Port, one of the busiest in the world, notes that “in the next few decades, access roads could be covered in water; rail lines, either from heat or from ocean water inundation, would be unusable; electrified infrastructure such as cranes could stop working. The piers themselves, particularly older piers in the center of the sprawling 3,000-acre Long Beach complex, would be swallowed by sea and flood water, leaving them inaccessible to trains and trucks”. As the Colombia study also notes in passing, ports in developing and emerging markets may often also have unpaved areas which can be damaged more severely by inundations.

In this context, many ports face both pressure to participate in mitigation/ decarbonization efforts, and pressure to think ahead about adaptation. On mitigation, ome larger ports have had the luxury of trying to get on the front foot in the public debate. Seven ports — Hamburg, Barcelona, Antwerp, Los Angeles, Long Beach, Vancouver and Rotterdam – announced in September 2018 the creation of a “World Ports Climate Action Program,” aimed at working together to find ways to reduce CO2 emissions from maritime transport. Their program has five action areas:

1. Increase efficiency of supply chains using digital tools.
2. Advance policy approaches aimed at reducing emissions within larger geographical areas.
3. Accelerate development of in-port renewable power-to-ship solutions.
4. Accelerate the development of commercially viable sustainable low-carbon fuels for maritime transport and infrastructure for electrification of ship propulsion systems.
5. Accelerate efforts to fully decarbonize cargo-handling facilities in ports.

The Port of Oslo last month announced a 17-point climate-action plan, with the goal of becoming the world’s first zero-emissions port. The port produces 55,000 metric tons of greenhouse-gas emissions a year. By 2030, the port aims to make an 85% reduction in its emissions of carbon dioxide, sulphur oxide, nitrogen oxide, and particulate matter. The plan includes refitting ferry boats, implementing a low-carbon contracting process, and installing shore power, which would allow boats to cut their engines and plug into the grid when docked. Shore power can also power equipment like cranes, which normally run on diesel. Oslo incentivizes replacement of diesel with lower port fees and electricity costs to reward compliant ships, and by revising contracting processes to command terminal builders and shipping companies to obey low-emission rules. Rotterdam, which is Europe’s biggest port, is using zero-emission port equipment, while two months ago the Port of Los Angeles unveiled two new battery-electric top loaders.

Oslo’s plan is also of specific interest in that Oslo is a major port for ferries running across the Baltic straights; these ferries are estimated to be responsible for half the port’s emissions, a function of their frequency. Oslo has awarded a contract to Norled to electrify existing passenger ships; Norled delivered the first electric refit in September, and the ship now has the equivalent of 20 Tesla batteries on board. In a further sign of growing interest toward electrification among the industry, last month Washington State Ferries, which runs the second-largest ferry system in the world, announced it is switching from diesel to batteries. Washington State Ferries carry 25 million people a year across Puget Sound, and its annual fuel consumption is on par with that of a midsize airline, making it the state’s biggest diesel polluter. The ferry operator’s electrification program will start with the three most polluting vessels, which consume 5 million gallons of fuel a year between them; switching the three ships to fully electric operations would cut emissions by an estimated 48,000 metric tons of CO2 a year, the equivalent of taking 10,000 cars off the road. This will also require a major quayside electrification effort. Canada’s British Columbia Ferry Services, another major operator, moved to LNG some time ago and is now eyeing electrification of its fleet. This August also saw the launch of the world’s largest all-electric ferry to date, a 200-passenger, 30-car carrying vessel in Denmark, while in July the U.K. government announced that all new ships would have to be equipped with zero-emission technology.

On adaptation, almost all ports will need to take some sort of action to deal with rising waters, and more frequent extreme weather events bringing flooding. Key areas will be in protecting goods being stored and moved within ports, and inland transport connections. So far, the approach being taken by most ports is the obvious one – trying to keep water out of where it’s not wanted, and European ports are in the forefront. Rotterdam, Amsterdam and London are known to be protected against a 1 in 1000-year event, or at least what has been thought of as 1 in 1000-year events. Rotterdam’s measures are of the highest level globally, consisting of two of the largest storm surge barriers in the world. London’s flood barrier is also among the biggest in the world. These kinds of defenses do not come cheap. According to a recent study by consultancy Asia Research and Engagement (ARE), upgrading some of the 50 largest ports in the Asia-Pacific region to help cope with the effects of climate chance could cost up to $49 billion.

Future port adaptation measures are likely to be far more extensive than those implemented to date, and to require more varied technical approaches. Chances are pretty good, as estimates of how much and how soon sea levels will rise keep getting ratcheted up, that current forecast numbers for seawall-type protections will escalate quickly – as in the example of San Francisco’s barrier, whose projected cost jumped in a few years from $50m to over $500m. Chances are also pretty good that other complementary solutions will be needed, along the lines of major drainage improvements and ways to elevate storage facilities. Unless some radical positive change takes place, rising sea levels are likely to inexorably make seawalls regularly obsolete unless they too keep getting (expensively) raised, and solutions that focus more on the parts of ports that have to keep dry make be most cost-effective. Finally, chances are pretty good that new kinds of private-public partnerships for adaptation will be needed. Inland connecting infrastructure is more often owned by local governments that port operations are, and those governments struggle more than port operators to find revenues with which to fund raising and hardening that connecting infrastructure. Ports may find they need to help governments put in place the improvements to connecting infrastructure, without which ports will find their revenue streams drying up – all puns intended.

Airports, Ports, and Climate Change (part I)

Airports, Ports, and Climate Change (part 1)
December 2019

Last month, Denmark announced that Kangerlussuaq Airport — Greenland’s main airport — is set to end civilian flights within five years due to the melting of permafrost cracking its runway. Infrastructure investors take note – this is the first airport worldwide to close due to climate change, but unlikely to be the last. A new greenfield facility will have to be built to accommodate future flights.

A year earlier, Osaka’s Kansai International Airport was largely closed for 17 days, when waves and winds from Typhoon Jebi breached a seawall. In June 2017, American Airlines cancelled 40 flights out of Phoenix, Arizona, as extreme heat made it too difficult for smaller jets to takeoff from the airport.

Welcome to the future of airports.

Climate change is arriving, faster and worse than most projections estimated. For airport operators and investors, this will entail more of the type of consequences already being seen in Greenland, Japan, and Arizona. The current Infrastructure Ideas issue will outline some of these consequences, while the subsequent issue will examine the future of ports in a time of climate adaptation.

Emissions Mitigation. The world’s airlines are expected to fly over 4.5 billion passengers in 2019 (yes, almost a flight for every person on the planet), up by a billion since 2015. This high growth is driving very large capital investment plans for airports, as well as rising emissions. The aviation industry is estimated to be responsible for more than 850 million tons of CO2 emissions annually, about 3% of all global emissions. Emissions from jets are thought to have more harmful effects than many other sources of emissions, as they get released higher up in the atmosphere. Given air traffic projections, emissions from aviation are projected to triple by 2050. This has led in the past few years to increasing concerns, in the context of increasingly dire warnings from the scientific community about the pace and severity of climate change. Already in 2016 the International Civil Aviation Organization, ICAO, agreed to cap carbon emissions from international flights, starting in 2021 – an agreement which may prove difficult to implement if passenger growth continues as projected. Some airlines are also trying to get on the front foot: United Airlines announced a goal to cut its greenhouse gas emissions 50% by 2050. How this will be done, and whether it will be enough to offset the onset of major regulatory limits, remains to be seen. As start-up technology companies explore the launch of “air taxi” services, domestic flight emissions may also see accelerated growth. Industry players should expect that there is likely to be increased conflict between political emission reduction objectives on the one hand and unabated passenger growth on the other. Therefore investors in the sector may do well to factor the risk of political action either taxing flights and/or limiting flights, and therefore reducing the overall needs for capital investment in airport expansions. Arguments can also be seen already that controlling the expansion of airports themselves is an important tool to curbing airline emissions (see Curbed, Want to Get People to Fly Less? Stop Funding Airport Expansions).

Airports themselves emit a tiny fraction of the GHGs that airlines do – at least directly. Their own operations are far less likely to face political pressure of the type that airlines will. Nonetheless a climate neutral accreditation exists and has enrolled many facilities, whose efforts focus on meeting energy needs through renewables and improved efficiency, on the use of hybrid or electric vehicles, and on public/group transit facilitation for employees. Potential emission reductions of this type may be largest in airports located in lower-income countries, which often see a combination of less-modern/ less-efficient operational equipment and older less-fuel efficient aircraft. Jomo Kenyatta International Airport in Nairobi, for example, has achieved major GHG reductions by purchasing power units for parked aircraft which run on electricity, rather than diesel as the older units had. This is good — yet the indirect emissions related to airports are significant, and may prove to be more of a political target in the future. Indirect emissions would be mainly two elements: how many flights airport capacity allows, and transport emissions from people getting to and parking at an airport. As noted above, activism is beginning to target the issue of airport capacity expansions as a means of curbing airline emissions. It is likely that in the near future, the efficiency of passengers reaching an airport starts attracting attention, with arguments for parking expansions to be replaced by public transit, for example. At one level further removed, one can also anticipate growing pressure for investment in passenger rail services, coupled with increased taxation of short-haul flights, to attempt to shift traffic from air to rail for short-distance travel (as most fuel is burned on take-off and landing, making short flights more carbon-intensive flights). The bigger climate change worry for airports, however, is likely to be adaptation.

Adaptation needs: water. Water has gone from a friend of airports to a foe. In many cities, airports were built near seacoasts to minimize disturbances to humans or avoid natural obstacles like mountains. Now that water is rising, and airports are some of the most vulnerable infrastructure to sea level rise. In the USA, 13 of the country’s 47 largest airports have at least one runway that is vulnerable to storm surge, including the giant facilities in New York, Miami and San Francisco. Globally fifteen of the 50 busiest airports sit less than 30 feet above sea level, while the OECD identified 64 airports as likely to be affected by the predicted rise in sea levels. Complete disappearance of facilities may be remote (for the extreme risk, see our previous Lessons from the Venice Floods), but higher water levels will exacerbate the effects of storms, making airport flooding far more common and damaging. And though damage will be more extensive and long-lasting for coastal airports, inland airports will not be exempt from water-related adaptation issues. More intense rain events, another predicted effect of climate change, will cause more frequent and damaging river flooding, as the US Midwest has been experiencing. Inland airports are also frequently sited near rivers, for the same reasons that their coastal counterparts are frequently sited along the shore, increasing their vulnerability to flooding.

The obvious approach to adaptation for airports is to try to keep the water out. San Francisco is Exhibit A for this approach, having announced plans for a $587 million seawall to protect its airport. When the project was first tabled, in 2012, it was designed for an 11-inch sea level rise, with an estimated cost of $50 million. Seven years later, with climate projections getting worse, the revised plan now calls for planning on a 36-inch rise and has increased the estimated cost by 1,000%. Across the bay, Oakland plans a $46 million project to fortify and raise by 2 feet the 4.5-mile dike which protects it. In Hong Kong, plans for the $18 billion third airport runway were revised to include a 21-foot high seawall. Norway, whose state-run airport operator Avinor has called almost half its airports “quite exposed” to potential sea level rise, has decided to build all future runways at least 23 feet above sea level (For more, see this month’s article in Wired, How Airports are Protecting Themselves Against Rising Seas). Moving the water that does arrive is also critical: airport drainage systems will need significant fortifying to move greater and faster-arriving amounts of water. At some stage, however, airports will face the same dilemma that coastal cities and seaside home-owners increasingly face (see previous column, Capital Punishment): keep investing in barriers to the sea, or move. When city leaders opt to move, as in the case of Jakarta, it will be difficult for its airport to remain viable.

Adaptation needs: Heat. After water, the next biggest issue for airports will be extreme heat. The curbing of takeoffs due to 120-degree heat in Phoenix garnered many headlines (see the New York Times, Too Hot to Fly? Climate Change May Take a Toll on Air Travel). Hotter air means thinner air, impacting the ability of planes with smaller engines to generate enough lift to get airborne. Extreme heat requires longer distances to take off and/or reducing aircraft weight (with fewer passengers or cargo). Airports in locations where high temperatures already occur frequently, and with short runways that limit planes’ ability pick up speed, will be especially affected. One of Air India’s general managers, Captain Rajeev Bajpai, notes that extreme heat is already an aviation problem in countries like Kuwait, where planes can be grounded on summer days because their electronics automatically shut down. Hotter temperatures may cause tarmac to melt, or as in the case of Kangerlussuaq, may cause the ground under the tarmac to melt. While the impact of these issues may not rise to that caused by rising seas, takeoff and weight restrictions, and more frequent tarmac repairs, all add up to substantial costs for airport operators – as well as disruptions to passenger and cargo transport. Higher cooling costs will be another obvious effect.

There will be other climate adaptation needs. ICAO notes that high wind, heavy precipitation and even lightning strike events that threaten facilities, and aircraft are growing more frequent. But dealing with water and heat will be the big two for airports.

Financing Implications. Adapting to climate change will require greater capital spending from airports, accompanied by greater uncertainty and low likelihood of associated revenue gains. The airport industry is already today a major infrastructure investor. According to Reuters, $260 billion in airport infrastructure projects are under construction worldwide. Those are big numbers, and climate adaptation needs will add more, as we can see from the costs of just the San Francisco and Hong Kong plans. The handful of 30-million passenger per year airports will most easily finance and absorb these capital costs. Issues are likely, however, to arise for the larger number of mid-size airports around the world. The problem they will face is that the capital costs for keeping water out are related more to geography than the volume of an airport’s operations, and mid-size airports may face similar adaptation-related capital costs to those of larger airports, but without the same revenue base over which to amortize them. It will be an expensive asymmetry for many airports. The second financial implication of adaptation, greater uncertainty, is also illustrated by the case of San Francisco – where in seven years the projected capital needed to hold off rising waters rose by a factor of ten as projected sea rise levels kept changing. “It’s going to be an evolving battle,” as says Patti Clark, a former airport manager who now teaches at Embry-Riddle College of Aeronautics. Capital expenditures needed for continued operations in 2050 may well look very different in 2030 than it does in 2020. These kind of investments also have the disadvantage they will not in themselves produce incremental revenues – they will just try to keep the ship afloat, so to speak.

Harvey Houston Airport flooding

Houston Airport after Hurricane Harvey

Lessons from the Venice Floods

Lessons from the Venice Flood
November 2019

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Venice is famous for its “high waters,” or Aqua Alta. The city has also been famously sinking in the past few decades. But even by its wet standards, early November has been remarkable – very unfortunately remarkable. On November 6, Venice saw its highest floodwaters since 1966: about six feet over normal high tide. Famous monuments such as La Fenice and St Mark’s were partly under water; the Aqua Alta bookstore, loved by tourists and Venetians for its habit of using bathtubs, plastic bins and even a gondola to display – and keep dry – part of its book collections, couldn’t stay above water. At the worst of it, water rose 10 inches in the span of 20 minutes. Even Venice’s one vineyard, home of the unique Doroma grape, was under threat. Then over the following week the floods returned… three times. It was the worst week of flooding in Venice since 1872, and at its peak floodwaters were the second highest ever recorded in the city. Thousand-year old St Mark’s has been previously flooded… five times. As this is written, the city remains flooded.

Unusual for sure. Notable for the fame of Venice and its monuments, visited by millions of tourists, for sure. A lesson in that more and worse flooding is coming to many famous waterside cities, as discussed in Infrastructure Ideas’ recent post on Jakarta (see Capital Punishment), again for sure. And also a lesson in what flooded Venice says about infrastructure and adaptation to climate change.

Increased flooding is already with us in many places (inland as well coastal, as reviewed in our earlier column “Floods and Infrastructure Investment”), and billions of dollars are already being spent trying to adapt. Many more billions are on the drawing board of infrastructure planners: this summer Wired reported the projected cost of protecting (just) US cities from sea level rise at over $400 Billion. Globally cost estimates are approaching the trillions of dollars.

A few things are already apparent from the billions being spent to attempt to stave off flooding. One lesson: flood barriers can be expensive – very, very expensive. New York City’s rebuilding of the Rockway Boardwalk after Hurricane Sandy cost $70 million per mile, and that was just for repairs. The Thames Barrier, in place since the 1980s to keep London dry, cost about $2 billion in today’s dollars to install. Venice – for here the story takes its major, intriguing, lesson-filled turn – yes, Venice, has spent billions to date on one of the biggest flood barriers in the world, “an underwater fortress of steel,” as the Washington Post called it. As reported by City Lab

What makes this round of destruction especially frustrating is that Venice’s massive flood defense system is almost complete. Costing almost $6.5 billion and under construction since 2003, the Venice Lagoon’s vast MOSE flood barrier is due to come into service in summer 2021. A string of 78 raiseable barriers threaded across the lagoon to block tidal surge, the MOSE project represent Venice’s moon-shot bid for survival in a warmed world.

Flood barriers are expensive. Venice’s experience also illustrates a second lesson for cities contemplating this kind of infrastructure investment: like other very large infrastructure construction projects, they take a long time to complete, and completion schedules only change in one direction. Venice’s barrier has been under construction 16 years: the original completion date was 2011, eight years ago. Had it been in schedule, Venice’s libraries, frescoes and squares would probably not be underwater today. When it will be available for use is unclear, and projected final costs reach as high $9 billion.

A third lesson is that, like with other major infrastructure construction, large amounts of funding may not wind up going where they are supposed to go. Venice’s previous mayor was arrested in 2014 and accused (never convicted) of siphoning off large amounts of money intended for the construction. A few months ago, before the floods, there were reports that sub-standard materials had been procured, and that repairs would be needed before the barrier was even used (a similar issue is currently plaguing the effort to extend the Washington DC Metrorail to Dulles Airport).

It would be good if the bad news ended there. But it doesn’t. The severity of this month’s flooding in Venice raises a fundamental question. After the billions, when the barrier is finally complete, how long will it last? A couple of decades?

Infrastructure planners and policy-makers in cities worldwide will be looking at many more billions of dollars in infrastructure spending to adapt to climate change-induced coastal flooding. Venice’s lessons indicate this infrastructure will require finding a lot of capital – some cities will find it, others will need to turn to national governments or the private sector, in public-private partnerships — to find the money. The lessons also indicate that planning, and construction, need to start sooner rather than later. Floods driven by sea-level rise and extreme weather events are rapidly increasing in frequency and severity, and every new projection shows problems coming sooner than the previous projections. Venice shows that flood barriers are not easy or quick to put in place. Venice also shows that spending controls and corruption prevention efforts will be important – with a lot of money comes a lot of temptation.

There are, of course, alternatives. Many cities are discovering the importance of smaller-budget “green infrastructure” efforts as part of their adaptation plans. Expanding rather than shrinking planted, permeable surfaces, preserving wetlands and other natural water catchment areas, green roofs and many other approaches can help reduce the incidence and impact of flooding. These approaches have the advantage of reducing the need for multi-billion dollar, probably delayed and more expensive than planned, possibly of rapid obsolescence, highly-engineered infrastructure investments. To a point. This would not have been likely to affect Venice’s situation much, though for certain cities the impact might be large.

And then there is moving. Indonesia is taking that route with Jakarta (sort of). Even culturally and historically important buildings sometime get moved. I once saw the Piva Monastery, in Montenegro: a 16th century church with remarkable frescoes, it was originally built in the valley of the Piva River, then relocated – stone by stone – in the 1970s during the construction of a reservoir for a hydroelectric complex. Adapting to flooding, in this case, intentional.

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.