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

China’s New Carbon Market

October 2021

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

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

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

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

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

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

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

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

Xi Jinping’s UN Coal Pledge

September 2021

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

Hot air?

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

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

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

Or pretty cool?

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

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

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

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

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

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

The Big Picture

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

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

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The Carbon Capture Business

September 2021

If you want to become the next Elon Musk, success in one infrastructure business will guarantee your untold riches: Carbon Capture. The only catch? Still being alive when it’s time to cash in.

At the rate efforts to stem carbon emissions are going, and observing how changed climate just from GHG emissions to date is affecting hundreds of millions across the globe, many parts of planet earth will become more and more unpleasant to live in. The latest IPCC report sounded its loudest alarm bells to date, and yet there are few political signs that getting gas-guzzling cars and trucks off the road, or shutting any significant fraction of the world’s coal-fired generating plants, is going to happen anytime soon. In the best of political will and consensus cases, we’ll still have way too much carbon in the air for the planet’s climate to be as we would want it – soon, and for centuries.

Enter Carbon Capture.

The idea of sucking some of that excess carbon out of the air — negative emissions — in order to reduce global warming has been around for a couple of decades now. Working prototypes first started appearing around 2015, and the biggest carbon capture plant to date was turned on just this week, in Iceland. It can actually work. At a very small scale, and a very high cost – for now. In today’s post, we’ll have a look at where this business is, and where it might be going.

Carbon capture comes in two basic flavors: point-specific, and general. Publicity and early investment have been more focused on the former, notably carbon capture facilities being tied to coal-fired generation – often referred to as CCS, or Carbon Capture and Storage plants. There are currently some 20 CCS plants in operation worldwide, with a combined capacity of about 40MT of CO2 per annum. The first large-scale facility was installed in 2014 at the Boundary Dam coal plant in Saskatchewan. The track record of these early efforts has been… mixed. While technical performance has generally been in line with expectations (an efficient CCS facility should be able to remove some 90% of an associated plant’s CO2 emissions), the overall economics have been marginal. A highly publicized effort to incorporate CCS onto coal-fired generation by Duke Energy was abandoned, and the PetraNova plant in Texas, the largest in the world when launched in 2017, was shut down earlier this year for losing money.

The International Energy Association (IEA), among others, remains bullish on CCS. While public attention has been primarily on CCS in conjunction with power generation plants, CCS can be applied to many kinds of industrial processes with GHG emissions. Facilities tied to plants which produce more concentrated CO2 streams – such as ethanol or natural gas – require less energy to separate out carbon for subsequent storage, and thus have significantly lower costs than those tied to power generation. The IEA notes that after a time of declining investment pipelines, plans for more than 30 new integrated CCS facilities have been announced in the last three years, with a combined CO2 capture capacity of around 90 Mt per year. That, however, is still less than 0.1% of estimated global CO2 emissions. The IEA stated earlier in 2021 that carbon-neutrality by 2050 would require the capacity to remove 1 billion tons of CO2 from the atmosphere every year. A recently issued report by the National Academies of Science puts that number 10 times higher, at 10 Gigatons per annum.

This week public attention has been on the other “flavor” of carbon capture, non-point-specific carbon capture, often referred to as Direct Air Capture (DAC). Instead of being located alongside a specific source of emissions, DAC facilities can be sited anywhere – often near potential carbon storage sites, and extract carbon from the atmosphere itself. According to Bloomberg New Energy Finance, the current global capacity of DAC is 6,415 tons of annual CO2 capture, to which the September 8^th launch of the Orca Climeworks plant in Iceland will add another 4,000 tons: a big jump, yet still a tiny fraction of the capacity of point-specific CCS technologies, which themselves are a tiny fraction of the excess CO2 in the atmosphere.

There are plans for DAC capacity to get bigger, much bigger, and we’d say the force is with DAC. There are three main players as of now – Climeworks, Carbon Engineering, and Global Thermostat. Bloomberg NEF says their capacity will “increase 150-Fold by 2024.” That would be the year in which Carbon Engineering plans to open a 1 million TPA facility. While this would still lag the impact and capacity of point-specific CCS technologies, we think that DAC has a couple of decisive advantages over CCS in the medium to longer term. The first advantage is location: a DAC plant (which essentially looks like a shipping container) can be placed anywhere, and extract CO2 that entered the atmosphere from any number of sources. At the far larger scales on the road to removing 1 billion tons per year, or 10 times that, from the atmosphere, not being tied to power generation or other industrial processes will become a big advantage. The second big advantage will be political attractiveness. In the next 1-2 decades, as political pressure to take action grows in tandem with global warming and its impacts on populations everywhere, and extracting carbon from the atmosphere gets seen more and more as one essential part of the solution, DAC will be a far more attractive place to channel global investment and subsidies. It is not that DAC doesn’t have a moral hazard problem – it’s just that DAC’s moral hazard is and looks far, far smaller than that of point-specific Carbon Capture. Some degree of public subsidy and support has flowed to CCS – the IEA says $2.8 billion in public grants have accompanied the $15 billion in private investment in already commissioned CCS plants, and places like Wyoming and North Dakota are lobbying hard for more. But environmental opposition to such support is already fierce – as it “rewards” large polluters directly, and scaling up such public support is going to be extremely difficult politically, if not impossible. In contrast, DAC doesn’t reward any polluters, and its own scale won’t be significant early enough to really impact the political debates around taxing, decommissioning or prohibiting fossil fuel usage. Yet the political demand for removing carbon from the atmosphere, just to make the problem less bad in the coming decades and beyond, will become huge – and DAC is far more likely to be the beneficiary of tax monies channeled to attacking that problem.

Issues

Several obstacles stand between today’s small-scale DAC and an eventual large-scale flood of public support and investment. Leaving aside the combination of moral hazard and the creation of public subsidies, chief among the obstacles are (i) costs, (ii) energy intensity, and (iii) what to do about the carbon.

DAC costs and business model. DAC is for now the most expensive of carbon capture technologies. According to Christopher Gebald, co-founder of Climeworks, current costs run at $600-800 per ton of CO2 extracted from the atmosphere; CCS costs related to power generation might run at 10-15% of this, between $60-120 per ton, while CCS costs related to more “pure” forms of CO2 emissions such as ethanol production can be as low as $20/ton (still leaving costs related to carbon separation and storage). Revenues are far lower, with the largest source presently from selling to oil companies for enhanced oil recovery – but even that isn’t high enough to keep some CCS plants in operation, and it is hard to envisage the petroleum industry paying much more. Some CO2 is recycled to industrial producers which use it as feedstock. Global Thermostat sells its DAC-derived carbon dioxide to soft-drink producers, but it is also hard to envisage a large-scale business model around this. For now, the economics of decommissioning coal fired plants is more attractive. The business model of DAC, however, may become more positive. Economics of scale will be a big factor: the Orca plant in Iceland was made entirely by hand; as demand and volumes increase by orders of magnitude, it should become far cheaper to build DAC plants, as we’ve seen happen in other technologies such as battery storage. Gebald of Climeworks projects costs at around $200-300/ton by 2030, and $100-150/ton by 2040. Steve Oldham, CEO of Carbon Engineering, claims that his company is already capable of building plants with costs closer to $100/ton. On the revenue side, larger, commercial-scale plants will allow DAC players to sell offsets to firms looking to reduce their emissions. But public sector payments are still likely to be the big revenue source for DAC. The first steps in this direction in the US were taken this Spring, with the passage of the 45Q rule, which provides a tax credit of $50/ton for captured and sequestered CO2.

Energy Intensity. Direct Air Carbon Capture is highly energy intensive – mostly a function of the fact that CO2 is a small fraction of the air DAC absorbs, meaning that energy needs for separation of the carbon are high. How energy intensive? Research firm Carbon Brief claims DAC could account for as much as 25% of global energy consumption by the end of the century (direct CO2 capture machines could use a quarter of global energy in 2020). DAC technology, however, is still far up the learning curve. Liquid solvents for example require a far lower temperature to run separation processes, in which case waste heat – at near-zero marginal cost – could become a replacement energy source.

What to do with the carbon? Storing the extracted carbon presents challenges. The issue is less the existence of potential underground storage with appropriate geology (less prone to re-release of the carbon than, say, forests which might get consumed by fires), and more with the need to get the carbon from where it is extracted to where it is stored. This is especially an issue for CCS, whose location is determined by emission sources such as power or industrial plants. A big part of costs and land issues for CCS, if this should scale up substantially, will be pipeline networks to transport the extracted carbon. Such pipelines exist today (piping carbon to oil fields for enhanced recovery), and studies are underway in several places for this kind of infrastructure at a larger scale. This should be less of an issue for DAC, which can be sited closer to storage areas, requiring far less transport infrastructure and investment. DAC is also less land-intensive than solar or wind farms, and unlikely to compete with other priority land uses, like agriculture.

The impact that carbon capture technology will have on reducing carbon in the atmosphere, over the next two decades, is likely to be… minuscule. Which, paradoxically, may help make it an even bigger business than it would otherwise be… maybe by 2050. By 2050 (and certainly way before), the political pressure to remove large amounts of GHGs from the atmosphere will have become enormous – unlike the tepid interest which the idea now attracts. By then DAC technology should have sufficiently matured to be more economic to operate, and be able to grow faster with fewer subsidies. As heat waves, mega-fires and super-storms occur in more places and more frequently than we’d want to imagine at this point – along with whatever other climate problems may be in store as global temperatures rise – there could literally be no end to the appetite for building more and more carbon capture machines. In the second half of this century this could be, no joke, the largest infrastructure business in the world.

A business that won’t be mature or profitable for maybe 25 years sounds like it’s too early for a good investment. Or maybe not.

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German Floods and Performance Bonds

August 2021

In mid-July, some 250 people were killed in Germany and Belgium as rain-swollen rivers flooded towns over a wide area. More than 10 inches of rain fell in 48 hours in some spots; Cologne received 6 inches in 24 hours. It was the deadliest natural disaster to hit Germany in over 50 years. Economic losses are estimated at over $3 billion, with the total likely to rise much higher. Germany was not alone in experiencing extreme rainfall in July. One Sunday, Londoners were hit with a month’s worth of rain within a few hours. In Central China, rain amount records were set, over a million people were affected, and the subway in Zhengzhou – a city of 5 million – flooded while passengers were trapped in trains. This a year after several million were displaced by flooding in the Yangtze River Basin. And in the Berkshires of Massachusetts, July 2021 became the rainiest year since records were first kept – in 1891.

In our previous column, Infrastructure Ideas wrote about rising water levels along coasts, and the infrastructure implications of plans to build seawalls to defend many cities. As last month has shown, once again, weather-related flood events are increasing far from the seas as well. Floods are both damaging existing infrastructure, creating repair and restoration needs, and triggering plans for new infrastructure investments to help cities adapt to rising flood risks.

Too much water in many places, and not enough in others. July’s extreme weather events were not limited to flooding: in the Western US, in Turkey, in Greece and in Sardinia, wildfires also set records and damaged widespread areas. Some of these wildfires are expected to burn on into the Fall. Much of the Western US also saw unprecedented heat waves in July, setting the stage for the fires – as did Moscow, among other places. Last year it was Australia. In an era of climate change, extreme weather events are becoming more common, and the IPCC — the Intergovernmental Panel on Climate Change – tells us that the frequency of these extreme events will increase as global temperatures rise. As a headline from the New York Times says “No One is Safe.”

From the standpoint of infrastructure, these floods, and the wildfires, share one important thing in common. They result from extreme weather events which are unpredictable.

General trends are clear: more floods in some places, and more heat and fires in others. Sea level rises are increasingly observable, and “predictable” in the short term. But the timing and scale of downpours is – generally speaking – not predictable, and neither are the location or breadth of wildfires. With Climate Change, we already observe that extreme events occur on shorter notice, with both more intensity and severity than before – and, as July has demonstrated, outside of any forecast range.

This lack of predictability, in an age of adaptation to climate change, has significant implications for infrastructure. The big implication is that related infrastructure investments — being made with a short (or no) planning period, and subject to a large range of uncertainties as to how soon they are needed, how frequently they’ll be used, and the magnitude of the problem they seek to solve — will tend to have some of the least desirable characteristics of infrastructure projects. Notably, these investments can expect to be characterized by (a) frequent design changes, (b) significant delay risks, and (c) large cost overruns. Frequent design changes will almost inevitably stem from the uncertainties involved, and from the politics surrounding how best to respond. Risks of delays and overruns go hand-in-hand with frequent design changes in all construction projects.

In normal times, public authorities asking for infrastructure projects, and lenders supporting the projects, always look to lay this kind of risk off to sponsors and construction companies. Completion guarantees from sponsors and performance bonds from construction companies are the primary instruments to shift these risks. A consequence of climate change, and the rapid rise in adaptation-related infrastructure investments, is that it will become more difficult for these risks to be shifted in the way public authorities and lenders typically require. The culprit will be unpredictability. With the higher risks of delays and overruns coming from that unpredictability, the size of adaptation-related infrastructure performance bonds will strain the balance sheets of many construction companies. Where sponsors themselves are also construction companies, required completion guarantees will make the problem worse. And the construction companies will note, often correctly, that weather-related sources of cost overruns – as well as overruns stemming from political disagreements on how best to respond to extreme weather events – are outside of their control, making them even more unwilling to take on these risks. We can therefore expect to see that many infrastructure investments intended to help cities and other areas adapt to more extreme weather events – urgent investments when the need for them becomes clear – will get at best delayed and at worse stuck due to the unwillingness of parties to bear the risks stemming from higher unpredictability.

Keeping infrastructure investments flowing as the need to adapt to extreme weather events grows may therefore require something new. For developing countries, funding for these higher risk investments may simply get swept up into their general need for additional finance related to climate change: yet one more problem to solve. For wealthier and middle-income countries, the solution may wind up in the domain of insurance. The likely best way to manage the risks from unpredictability will be diversification of that risk across a very large pool of geographies and projects. One model may be the World Bank’s Disaster Risk Financing and Insurance program, developed in the mid-2010s, which was created to pool weather-related risks for low-income countries.

Floods in Germany, fires in the Mediterranean, these are disasters whose occurrence, timing and scope are increasingly unpredictable. Yet that such events will occur more frequently is itself predictable. Infrastructure investments may in at least some cases mitigate the damages and deaths from further extreme weather events, and will in many cases be needed to repair damages. These adaptation-related investments will present different problems than traditional infrastructure, due to the unpredictability of specific severe weather events. The biggest problem is likely to revolve around Performance Bonds, and the ability of construction companies to absorb unpredictability risk. Let’s hope insurance can provide a solution.

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Seawalls and Emerging Markets

July 2021

Built on beautiful Biscayne Bay, money has flowed from the sea to Miami – especially to its real estate developers — for centuries. It is starting to flow back to the sea.

Last month, the US Corps of Engineers released a draft study for how best to protect the city of Miami from rising seas and recurring flooding. The Engineers’ recommendation: a $6 billion, 6-mile long, and up to 20-foot-high seawall. City and state politics are now mired in a high-profile back-and-forth on whether to proceed (see “A 20-Foot Sea Wall? Miami Faces the Hard Choices of Climate Change”). Similar plans to build large and expensive seawalls are being debated in other American cities: Houston, San Francisco, Charleston, and Honolulu for a few, with New York City looking at the most grandiose plans of all, costing well over $100 billion. A 2019 report noted that the cost of building the seawalls under debate in the US could run to $416 billion – the same cost as the build-out of the entire national interstate highway system. Across the Atlantic Europe already has seawalls in a number of places: Venice, London, St Petersburg, the Netherlands. A gargantuan project – nearly 400 miles long – is under discussion to protect European coastlines along the North Sea – at a preliminary cost estimate of half a trillion dollars. Along the Pacific Singapore and Shanghai are among (the few and wealthy) Asian cities with seawalls.

There is still novelty around the idea. Until the last decade, one would have been hard pressed to find “seawall” in anyone’s definition of infrastructure. Ports have built jetties in many places to protect harbors, but these have been much smaller endeavors. Yet the future where one can plausibly project seawalls becoming one of the 3 or 4 largest categories of infrastructure spending around the world, capturing hundreds of billions of dollars, has come quickly. A future where seawalls will be the single largest ticket item in the budget of many coastal cities, at times dwarfing their combined spending on all other infrastructure combined. This is another example of how disruptions have upended the once stable and fairly predictable world of infrastructure, whether disruptions from technology – such as wind turbines or batteries – or from other sources, like climate change.

Fear of rising sea levels from the melting of glaciers is galvanizing the newfound interest in seawall building. Hundreds of millions of people live in coastal cities with low elevations and many, like those in Miami, are already seeing the increased flooding that will worsen in coming years. As the World Economic Forum states, “Even if we collectively manage to keep global temperatures from rising to 2°C, by 2050 at least 570 million cities and some 800 million people will be exposed to rising seas and storm surges. And it is not just people and real estate that are at risk, but roads, railways, ports, underwater internet cables, farmland, sanitation and drinking water pipelines and reservoirs, and even mass transit systems.” Estimates of the sea level rise itself, which may sound small or slow, tend to understate the problem. Only about 1/3 of future coastal flooding risk is from rising sea levels that would permanently submerge low-lying areas, while 2/3 of the risk comes rather from the likely increase in extreme high tides, storm surges and breaking waves. Cities are looking at a variety of ways to protect themselves, looking to better absorb and drain water faster, but attempting to keep water away is on nearly every wish list.

New research (see “A Space Laser Shows How Catastrophic Sea Level Rise Will Be”) shows that for several of these coastal cities, the issues of rising seas and more severe storms will be made worse by yet another problem: sinking. As populations in many of these urban areas have grown rapidly, over-extraction of ground water is causing the ground to subside. Cities built on river deltas usually sit on several layers of clay, deposited over time as sediments by the river, with underlying aquifers. When the aquifers get drained to provide water to the city’s population, the clay collapses into the space which had held water. The more an urban center grows, the more people it needs to hydrate, which increases the rate and severity of subsidence. Djakarta is the prime example of this effect, with subsidence having been a key factor in last year’s decision by the Indonesian government to move the capital to a different location (see Capital Punishment (or So Long, Djakarta ?)), but it is far from the only one.

The surge in interest in seawalls as the centerpiece of the solution for many cities will keep engineers occupied and planners preoccupied. It is still very early days in the growth of what will likely be one of future infrastructure’s largest areas. Today we’ll look at just a couple implications of this coming boom, especially as regards developing countries.

We’ll start with one safe assumption about this new type of infrastructure: if the seawalls get built, they’ll cost a lot more than the amounts now projected – even the $400+ billion estimated for the US. Seawalls will fit squarely into the type of infrastructure prone to frequent and large cost overruns (think of tunneling projects, like Boston’s infamous “Big Dig,” or of large hydroelectric dams, with average overruns approaching 50%). They will be highly politicized investments, with continued debate about every detail (whose property is disturbed, whose views are affected, which houses are outside the protection zone, what is the timeline – and especially, who pays), and debate about just how high the tidal or storm surges they’re built to prevent will be and how soon. This means the construction of these barriers will be subject to frequent change orders, the perfect recipe for more cost overruns. And they may become obsolete fairly quickly, depending on the pace of climate change and glacier melt in the coming decades. It would not be a big stretch to see the US spend over $1 trillion on seawalls in the coming 20 years, nor would it be a big stretch to see global spending on such projects well over $5 trillion. That’s a lot of infrastructure spending

A second safe assumption about seawalls? You won’t find many in Emerging Markets any time soon.

And that will become a big deal.

Cities in lower-income countries stand to be disproportionately affected by rising seas. While all coastal cities will be affected by sea-level rises, some will be hit much harder than others. Asian cities will be particularly badly affected. About 4 out of every 5 people impacted by sea-level rise by 2050 will live in East or South East Asia – several hundreds of millions of people. Africa is also highly threatened, due to rapid urbanization in coastal cities and the crowding of poor populations in informal settlements along the coast. The list of most affected cities includes Mumbai, Kolkata, Dhaka, Guangzhou, Rangoon, Ho Chi Minh City, Manila, Dakar, Alexandria, Lagos, Abidjan, among many others. Leaving aside China, most of these Emerging Markets cities and their national governments have one thing in common when looking at seawalls as part of their adaptation plans: a lack of capital.

The list of Emerging Markets countries with cities affected by rising seas looks an awful lot like the list of Emerging Markets countries with large infrastructure deficits – already. The capital requirements for building seawalls to protect their coastal cities from increased flooding will absorb a large share of their capital that is already needed for deficient infrastructure: for some smaller countries, the cost of seawalls may approach the size of their entire current infrastructure budgets. It is no surprise, therefore, that a list of cities actively considering seawalls is 90%+ in developed markets (including China). Djakarta – banking on financial support from the Netherlands – is the only city in a lower-income country with an advanced plan.

While it is not surprising that attention to seawalls is almost entirely concentrated in more developed countries, the absence of such attention in Emerging Markets has some important implications worth noting.

1. Flooding increases in coastal cities and the inability of those in low-income countries to engineer solutions (or at least what may appear to be solutions) to offset sea-level rise will lead to much larger-scale relocation of populations in the Emerging Markets than what we will see in the US, Europe and the richer Asian countries. Some of that relocation may be organized, at least to an extent, along the model of Indonesia’s announced move of the country’s capital, and much of it is likely to be dis-organized, in the form of migration – in country where inland options may be available, and cross-border where those options are not available. As the World Economic Forum states it, “The coming decades will be marked by the rise of ex-cities and climate migrants.” To date much of this climate migration has been relatively “invisible,” contained within countries. Don’t expect this to continue. The cry we have seen in early 2021 for better equity in the distribution of COVID-19 vaccines may presage a louder cry in years to come for better equity in the building of seawalls.

2. Given that the wealthy countries that dominate the Boards of International Financial Institutions will want to see as little large-scale cross-border migration as possible, and will have to devote plenty of capital to their own climate adaptation plans, we will undoubtedly see a big push for the IFIs to engage in helping Emerging Markets fund seawalls. With the scale of the financing challenge, this will be the domain of the large global and regional multilateral development banks, and will stretch their balance sheets. Should a large-scale Climate Adaptation Fund emerge, as has been discussed for many years, and could safely assume that a large share of its capital would wind up going into this area.

3. There will even greater interest in “innovative financial solutions” than there is for traditional forms of infrastructure. Don’t be surprised to see mechanisms through which the local private sector in coastal cities (especially companies serving consumers in these cities, such as retail, telecommunications, and producers of consumer goods) “help finance” some kind of Public-Private Partnerships (it will sound better than to say they are being taxed) in order to preserve their own revenues. And don’t be surprised to see some mechanism emerge whereby wealthy countries contribute to some kind of “Fund” to help finance seawalls in lower-income countries. It would be the same kind of general principle which has been discussed now for decades for Climate Change adjustment funds, but would have the clear advantage, relative to current discussion, of going to concrete (pun intended) objectives. In the US, we have seen the building of a wall to limit immigration generate considerable political momentum: one can imagine building of walls further away, with the same idea of limiting immigration in mind, will also generate plenty of political momentum in the future.

Seawalls: coming soon for infrastructure budgets – ready or not.

Index to previous Infrastructure Ideas columns about Climate Adaptation

Asia’s Energy Transformation: Vietnam

June 2021

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

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

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

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

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

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

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

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

Previous Infrastructure Ideas Posts on Energy: Index

The Water Wars are Here

September 2020

As we write in mid-September, Hurricane Sally has stretches of the US Gulf Coast well under water, and Japan is still recovering from the flooding of Typhoon Haishen. Yet while way too much water is the problem in some places, not enough water is the big problem elsewhere. A Washington Post headline on September 15 captures the latest example: “Mexican famers occupy dam to stop water payments to the United States.” Infrastructure Ideas believes we’ll see many more of these types of headlines, and in this issue we’ll explore some of the implications for infrastructure.

The ongoing conflict in the Mexican state of Chihuahua featured in the news is tied to a long-standing, complex arrangement. Under a water-sharing treaty signed in 1944, Mexico and the United States annually send water for irrigation across the border in both directions – three-quarters flowing south to Mexico. The issue which has flared up now is the different geography of water flows: Mexico’s share is sent north from the Rio Grande and Conchas rivers, mostly from Chihuahua, while the US share is sent south from the Colorado River elsewhere along the border. Local farmers in Chihuahua have occupied the Boquilla dam, on the Conchas River, to protest the central government’s sending water across the border. Mexico’s national guard was sent to clear out the protesters, killed one protester and failed to dislodge the farmers. A leader of the protest said “We tried to have a dialogue, but nobody listened to us. We are prepared to stay here and defend our rights to this water.” A second protest broke out this past weekend at the Cuidad Juárez border bridge, demanding justice for the death at Boquilla and the cessation of water flows.

Mexican Riot Police Guard Dam in Chihuahua (Washington Post)

Leaving aside the specifics of the Chihuahua situation, one does not need to go far to observe similar protests. Driving last week in record-breaking heat along California’s Central Valley, we could see every twenty miles or so, interspersed among the unending line of fruit orchards, signs calling for more dam-building to provide water to the Valley’s farmers.

In the American West, conflicts over insufficient water supplies have raged for over a century, though not coming (at least recently) to the armed conflict appearing in Chihuahua. As Climate Change creates more drought conditions in more places, these conflicts will only grow. While some of the coverage of the issue tends to melodramatic and/or dystopian, the science behind what will happen and where is getting much more precise. Over 500 past and present water-related conflicts are catalogued by worldwater.org, and earlier this year a new analytical tool was launched to help predict where such conflicts might arise, and it is not too early to focus on the practical infrastructure consequences.

We see five principal implications from these growing water shortages for infrastructure:

more demand for long-distance water transport
lower reliability of the same, and need for investors to focus not only on support from political leaders, but also broader support from local population,
more demand for local/smaller dams
greater focus on efficiency of water infrastructure
a push for more widespread pricing of water

Let’s look at each of these implications in turn.

More demand for long-distance water transport. Three inter-related drivers will create growing demand for water pipelines and canals: increased Climate-Change related water-stress in many places, population growth, and continued growing urbanization. These drivers will mean that at the same time cities demand more water for taps and showerheads while farmlands demand more water to grow the food that increased numbers of city-dwellers consume. Local water sources, whether from rivers or underground water tables, in many areas either are failing to keep up with demand growth or diminishing altogether. Cities have historically found it more politically expedient to address such problems first by buying needed water from elsewhere, before asking their citizens to change their ways. In some cases that elsewhere can be a very long ways away: the longest water pipeline today is the “Great Man-Made River,” which stretches over 1,000 miles and provides water to the main cities of Libya. It will soon have a rival for this distinction, as the “North-South Water Transfer Project” in China, under construction since 2015, aims to deliver water to China’s southern cities over close to 2,000 miles of pipelines. The Trans-Africa Pipeline (TAP), now on the drawing board, seeks to pump water across the Sahel over an even longer 5,000 miles. Most future pipeline projects won’t be this long, but they will still be long enough to very expensive, both in construction and operation – as moving water across long distances is highly energy-intensive (when water is not being pumped up hills, dampers have to slow the water on downhills). Both the politics and the economics of these projects will be immensely challenging, but nonetheless we can expect to see their numbers rise.

Lower reliability of long-distance water transport arrangements. More demand is not the same as more reliability. The current conflict in Chihuahua perfectly illustrates the dynamics that are likely to accompany a number of water pipelines or canals. Recipients insist on receiving their contracted allotments, climate change creates unforeseen water stresses in the area sending water out, and local populations protest decisions made by central authorities elsewhere. For those relying on the pipelines, or in the case of private financing those investing in the projects, the lesson is to not rely solely on agreements made by central political leaders, but to understand the degree of support from the local population in the area from which the water is coming. This political risk will layer on top of good old-fashioned construction risk, with high chances of major delays and cost overruns in these types of projects, while Global Warming will increase evaporation in many canal-based systems (between 2000 and 2014, the inflow to the Colorado River went down by nearly 20%, with 1/3 of that reduction from global warming). Infrastructure Ideas has also written previously about the growing cyber-risks associated with some infrastructure systems, and long-distance water transport control systems could be a prime area of vulnerability.

More demand for local/smaller dams. Where bringing water from far away is too difficult, too expensive, and/or risky, we will see demand for local authorities to create insurance in the form of more close-by reservoirs. The current advocacy by large-scale agro-industry in California Central Valley is one of many examples. In many cases, such projects will be politically appealing, but not always likely to solve the underlying problem – dams not receiving enough supply of water will themselves become dry, which is part of the problem at the moment in Chihuahua. Dam-building also suffers from a high degree of construction delay and cost overrun risk, and potential co-benefits from dams which may be argued by producing clean energy are likely to bump into the increasingly unattractive cost of new hydropower generation. Nonetheless, we expect that political appeal will see an increase in this type of infrastructure projects.

A greater focus on efficiency of water infrastructure. Efficiency has historically been the poor stepchild of the water sector. Up to 30-50% of water supplies are lost in pipelines, whether long-distance or simply in consumer distribution systems, due to a combination of poor management and other priorities. Among other things, shiny new pipelines or treatment stations have always looked politically more appealing than the nitty-gritty of reducing leaks. As more places feel the pinch on water supplies, and the difficulties of executing large construction projects such as pipelines and dams become more apparent, we can expect efficiency to climb up in priority. There is no shortage of examples of better technology and practices from which city authorities or water management companies can choose. Among others, miniaturized, submersible drones are likely to become in high demand as a tool for reducing the costs and improving the speed of finding and fixing leaks (see Infrastructure Ideas’ “The Drones are Here” for previous coverage).

More widespread pricing of water. “Free water” is an idea which is politically and ethically appealing. In low income areas, the argument for free water will remain strong. Yet at the same time, the absence of economic incentives for avoiding the waste of water – especially for large users – has long been an impediment to water conservation and efficiency. For the same reasons as discussed immediately above, one can expect that a greater focus on efficiency of water infrastructure will be accompanied by a push for more widespread pricing of water. This in turn will enable more cities and regions to tap into private capital for financing a part of their growing bills for water infrastructure – if they can overcome political resistance. As has been seen in many places, that resistance is often the fiercest coming from large users, and not from poorer segments of the population.

It would be nice to be able to give a sixth likely infrastructure implication from the growing incidence of water conflicts: greater policy coordination. The non-existence of such coordination or cooperation in many places is a large factor the spreading geography of water shortage, the American West being one of the most prominent examples. Unwillingness of political actors to speak with each other, or the inability to maintain such dialogue consistently, bedevils water use from the Nile to the Himalayas to Indochina. Regrettably, with populism on the rise in so many places, trailing unilateralist tendencies in its wake, it seems hard to imagine greater policy coordination on the horizon anytime soon. One can always hope.

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.