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.

Index of Previous Columns on Energy Markets

Index of Previous Columns on Climate Adaptation

The Future of Natural Gas Pipelines

July 2020

The month of July was not kind to the Oil & Gas pipeline business. In a span of days, three major US pipeline projects were halted, in three different parts of the country. The headliner was the Atlantic Coast Pipeline, a US$8 billion 600-mile natural gas pipeline project across West Virginia, Virginia and North Carolina: at the end of June, sponsors Dominion Energy and Duke Energy won a major battle at the US Supreme Court, receiving approval to cross the Appalachian Trail; a week later, the sponsors issued the stunning announcement that they would no longer seek to complete the project. That same week, the Dakota Access Pipeline, after years of protests and battles with lawsuits, was ordered by a Federal Judge to cease transporting oil from the shale-oil fields of North Dakota to the Gulf of Mexico. The Williams pipeline was intended to bring Pennsylvania fracked natural gas to the New York City area through a 200-mile pipeline, at a cost of over $1 billion, but – again the same week — failed to obtain its needed permits from either the state of New York or the state of New Jersey. Yet another project, which has faced high-profile legal challenges for years without getting off the drawing board, the Keystone XL oil pipeline, saw an appeal from the current US administration to let it proceed turned down by the US Supreme Court. A New York Times headline at the end of the week asked “Is This the end of New Pipelines?”

Infrastructure Ideas had reviewed recently the prospects for the Natural Gas business as a whole (“What Next for Natural Gas?” from June 2020). This post takes a follow-on look at the business of natural gas pipelines. And a rising new competitor in energy transport.

It seems like only yesterday that the natural gas pipeline business was booming, a bright spot where so few large infrastructure projects were proceeded. In the US alone, there are ongoing projects involving some $60-80 billion of investment in Oil & Gas pipelines, and projects worth close to $100 billion more have been announced. Now the future looks uncertain, at least for any pipelines crossing outside of Texas and neighboring friendly states. The same factors that have turned the situation upside down in the US are not yet playing out with the same visibility in the rest of the world, but one should expect that they will.

Environmentalism gets the loudest credit for derailing the pipeline projects in the news. In the case of the Atlantic Coast Pipeline, legal challenges – based on “Not in My Back-Yard-ism,” environmental concerns along the planned pipeline route, and climate change concerns – had major impact. The estimated costs of the project rose from $5 billion to $8 billion due to the related delays, and even a Supreme Court victory on one issue was no insurance against the risk of successful challenges on other issues. Dominion CEO Thomas Farrell told investors “To state the obvious, permitting for investment in gas transmission and storage has become increasingly litigious, uncertain and costly.” A piece in Forbes along the same line pointed out that pipelines were increasingly losing in the courts.

One aspect worth noting of the court decisions tilting against pipelines is the role of insufficient due-diligence. The current US administration, among others, has sought to increase the level of infrastructure investment by encouraging the bypassing of environmental and social reviews, which is precisely what sank the Dakota Access Pipeline. In the case of the ACP, judges repeatedly found that reviews had been inadequate and incomplete, forcing delays and cost increases.

Yet while environmentalism played a major role, what really bodes ill for the pipeline business, and what underlay the decisions made this month going against the projects, is economics. The price of electricity from wind and solar increasingly is beating the price of electricity generated from natural gas. Economics going forward will only get worse. Technology is continuing to make solar and wind power cheaper, while natural gas prices are now, on the one hand, too low to enable many players in the business to stay afloat and explore and develop more gas reserves, and on the other hand being pushed up as the cost of transport pipelines are going up. Combine this with the kind of regulatory concerns over emissions which have been growing in the US northeast, and more recently Virginia, and you have a battle going increasingly in favor of renewables, and increasingly against natural gas. A report out of the Goldman School of Public Policy in Berkeley last month went as far as claiming that the US electricity grid could lower rates while getting 90% of its supply with no greenhouse gas emissions by 2035.

In a tell-tale sign of how big the ongoing shift is, the same day that it and Duke Power announced they would abandon their $8 billion project, Dominion Energy also announced that it would sell most of its natural gas assets to Warren Buffet’s Berkshire Hathaway, in a transaction valued at close to $10 billion. The sale includes over 7,000 miles of natural-gas pipelines. For a utility that has relied almost exclusively on coal and natural gas, and been one of the staunchest defenders of fossil fuels, the two announcements heralded a major watershed. Dominion, the 6^th largest US utility by revenue, will instead shift its business to wind and solar power. It is already competing to become of the largest players in the burgeoning offshore wind industry (see “Offshore Wind: the Next Big Thing,” January 2020).

Coincidentally, the book out this month Lights Out: Pride, Delusion and the Fall of General Electric by a pair of Wall Street Journal reporters, focuses on the massive losses incurred by GE Power, one of the biggest players in the energy business worldwide. Most of the blame for these losses, along with general opacity of finances and practices, is laid in the book at the feet of decisions made by former GE CEO Jeff Immelt to bet the house on natural gas – especially with his single largest acquisition, that of French natural gas turbine producer Alsthom. Too much, too late, for the natural gas business.

Contrast the fate of the O&G pipelines with that of the Grain Belt Express. One big energy transmission project which is going forward in the US at the moment is the 800-mile, $2.3 billion, 4-Gigawatt high-voltage power transmission line, which will tap convey wind-generated power from Kansas through Missouri and into Indiana and Illinois. This is also a new generation of energy transport: the high voltage DC/ Direct Current line. Today’s transmission lines run on alternating current, and AC transmission involves significant energy losses over distance. In a future where renewable energy resources are often located far from the centers of consumption, long-distance DC lines like the Grain Belt Express will be a major focus of new infrastructure investment.

Outside of the US, chances are that new opportunities to invest in natural gas pipelines will also be limited. China is certainly one place where more will be built. But there the assets will be owned by the Government. The Government announced in late 2019 that it would establish a National Oil & Gas Pipeline Company (“Pipe China”) by combining pipelines, storage facilities and natural gas receiving terminals operated by China National Petroleum Corp (CNPC), China Petrochemical Corp (Sinopec Group) and China National Offshore Oil Company (CNOOC). Beijing aims to complete the asset transfers and start operation of the new entity – valued by industry analysts at more than $40 billion – by October 2020.

In Europe, the mega-project pipelines envisaged to bring either Russian or Caspian Sea natural gas to western Europe consumption centers will face an increasingly precarious future. Incentives to built wind and solar resources have always been more generous in Europe than elsewhere, and combined with the ever-cheaper availability of wind and solar, will make natural-gas generated electricity begin to look like an expensive choice. We can also anticipate that, as concerns around climate change continue to grow, political pressure to reduce or eliminate energy-sector greenhouse gas emissions will be strongest in Europe. This is increasing the risk that, even with long-term offtake contracts in place, the owners of pipelines bringing natural gas to Europe will face the kind of scenarios which have played out in the US this month: legal challenges and regulatory decisions that shorten their life-span significantly.

In the rest of the world? LNG import terminals will retain their attraction for a time, as they raise few of the local environmental and social concerns, notably rights-of-way, which arise with pipeline construction. But the future of within-border energy transport increasingly looks to be with long-distance DC electricity transmission lines, and not with natural gas pipelines.

What Next for Natural Gas ?

June 2020

2019 was a record year for Liquified Natural Gas (LNG) producers and shippers. Global demand continued to grow strongly, 12.5% from 2018, to a record 359 million tons. Imports grew mostly to Europe, but also to South Asia. Relative newcomers to LNG imports, Bangladesh, India and Pakistan imported a collective 36 MT. Consumption in China, the third largest importer after the UK and France, grew 12%, continuing to outstrip domestic production growth. The year-to-year increase in trade, at 40 MT, was itself another record, and brought the increase for the last four years to 95MT, meaning the LNG market had increased by almost one-third in only three years. The spot LNG market, which facilitated flexibility in sales compared to standard long-term contracts, had grown from just over 10% of the market at the beginning of the decade to nearly 1/3 of all sales. The market had grown so attractive that the rush was on to jump in: 30 MT of new capacity came on stream in 2019 – on top of 100 MT from 2016 to 2018, and financing for 71 million tons of new capacity reached FID. Meanwhile on the domestic side in the US, natural gas continued to be attractive as a source of supply for new power plants as coal capacity is being phased out – with gas now being far cheaper than coal. Of the last 29 GW of coal power generation retired, 23 GW have been replaced with natural gas, especially in the large PJM interconnect market.

2020, after the record 2019, could have hardly have come as a bigger shock for the gas industry. Thanks to COVID-19, 2020 will see the largest annual drop in energy investment in history: 20%, according to the International Energy Association. The projected drop in investment in oil & gas is even larger, 33%, and after the record 2019 for new LNG FID decisions, the expectation for 2020 is… zero. Natural gas prices have been hovering around historical lows of $2/MMBTU. Oil prices have shown some recovery, after the Saudi Arabia-Russia deal to curb surpluses, but the global gas market remains extraordinarily oversupplied. With LNG storage nearing capacity, as happened in April for oil, the worst is likely still to come, and negative prices for LNG cargoes late this Summer cannot be ruled out. Unlike the oil market, there’s been no sign of a coordinated response to address the glut, meaning the fallout could be deeper and longer. For the fracking-focused companies in the US, the outlook was already grim, and it is only getting worse: in 2019 42 E&P companies filed for bankruptcy, involving over $25B in debt. Moody’s noted “We are seeing slowdowns and negative cash flows spill over into the oil services sector that relies on the E&P companies for their business, and heavy hitters such as Schlumberger and Halliburton recorded significant losses in 2019.”

Natural gas tanker

So what’s next?

Optimism has been ruling projections of the future of natural gas for several years. With the increased production from the development of new E&P technologies, and a vast increase in investment in transport capacity, natural gas became cheaper than all other fossil fuels – including coal – and far more widely available than before. With growing concerns over carbon emissions and climate change, gas also benefitted from being seen as better than coal on the environmental side. Forecasts at the end of 2019 projected a near-doubling of global LNG demand from 2018 to 2035 (McKinsey, Shell), outpaced by even faster growth in supply – excess supply was expected to keep prices low into the mid-to-late 2020s. In the US, a 20% growth in demand from the power sector was seen by 2025, and the industry announced plans for some $30B in new interstate pipelines over the next five years. Only the production end, as noted above, was seen as facing continued difficulties.

Optimism is now on hold, pretty much across the board. In one year, LNG prices in Asia – the highest in the world — plummeted from $12/MMBTU to $2/MMBTU. Courtesy of the IEEFA, here is a list of the LNG projects put on hold or cancelled in the last three months:

• March: Santos-Barossa/Darwin (Australia); Sempra-Costa Azul/Port Arthur (Mexico-USA); Woodfibre (Canada); Woodside Energy – Pluto Train 2 (Australia); Shell/ETP – Lake Charles (USA); Magnolia LNG and Bear Head (USA-Canada)
• April: Qatar Petroleum – North Field East (Qatar); Shell Crux (Australia); Exxon Rovuma (Mozambique); Golar/BP Grande Tortue (Mauritania and Senegal); Pieridae/ Goldboro (Canada)

McKinsey’s annual natural gas outlook for 2019 had noted that of the 100 projects potentially planned to add new LNG capacity, each would need a maximum full break-even price of $7 per million British thermal units (MMBTU) to stay competitive: more than three times current prices in Asia – the “strongest” LNG market, with prices possibly heading still lower.

For the US power market, probably the largest user gas user, forecasts from the EIA have now shifted significantly. In 2019 the EIA had estimated natural gas would be the largest segment of the US power market until well beyond 2050, with an 8% higher share than renewables even in 2050. The new 2020 EIA outlook instead sees renewables with a 2% higher share than gas by 2050. Interconnection queue requests across all the major North American markets show that over 90% of new requests now consist of solar, wind and storage. This is spite of gas prices not only being low being getting even lower. The problem? A combination of costs and policy. From a cost standpoint, the fall in natural gas prices is being paralleled by continued technology improvements and falling costs for wind, solar, and energy storage. The cost declines of wind and solar, being technology-driven, are unlikely to reverse themselves, whereas the cost of declines of natural gas, now being driven by supply-demand imbalances, have an unpredictable future. From a policy standpoint, the “climate honeymoon” of natural gas has waned, if not ended. Three converging environmental trends are working against natural gas: (1) growing concerns on the climate front, as this week’s news indicate that even lower emissions during the COVID epidemic do not seem to have reduced atmospheric carbon levels, and climate change projections continue to get worse; (2) new studies of methane leaks are increasingly raising estimated average emissions from natural gas related projects, making natural gas now seem only marginally better than coal on the emissions side, and far less preferable than renewables; (3) studies on fossil fuel pipeline environmental effects are also raising the level of concern of damage from natural gas transport (a study of the 2010-2018 period in the US documented more than 5,500 total pipeline incidents, more than $4 billion in damages, and evacuations of almost 30,000 people – with a strong and unexpected correlation between the number of problems and how new the pipelines were). A number of US cities (San Jose is the largest) and utilities have moved to impose bans on new natural-gas infrastructure. Even existing gas power plants are becoming policy conversation targets, for possible replacement by cheaper renewables: in mid-2018, already, GE closed a $1B natural gas plant in southern California only 10 years into a planned 30-year life. Even the more politically conservative Midwest has seen regulators decline to endorse new gas-fired plants. In Europe, the European Investment Bank (EIB) announced in November that it will stop backing fossil fuel energy investments, including natural gas, in 2021 unless they negate their emissions through carbon capture or offsets.

The answer to what’s next for gas is, well, not much fun. At least for gas exploration, production, and transport companies. On the one hand low prices are likely to persist, which will lead to an increased number of bankruptcies in the E&P sector, and keep investors in LNG liquefication, transport, and gasification on the sidelines for any new projects, possibly into the middle of the decade. In the short-run, existing importers using spot prices (and not locked into long-term contracts) will see a windfall of cheaper gas imports. Importers locked into long-term contracts at higher prices may well take the opportunity to push for downward price renegotiations from suppliers, and in some cases possibly even walking away from contracts: when the contracts were entered into, accessing natural gas supplies looked difficult, in the future this is unlikely to become the case again anytime soon. The decades-long seller’s market is now a buyer’s market, for the foreseeable future. Good for users, but making it even worse for producers. Policy concerns in Europe and the US on emissions will likely keep dampening demand in a way that previous projections had not captured. This will leave Asia as increasingly the only attractive market for sellers. For the power sector, “peak gas” may arrive very soon, at least outside of Asia. In turn, expect natural gas suppliers to become more dependent on non-power demand, where electrification will take longer to materialize. That 100% increase in global LNG demand over the next two decades forecast at the end of 2019? It may have a hard time reaching 50%.

Silver Linings

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

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

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

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

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

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

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

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

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

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

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

Money for Coal

March 2020

At least in Germany.

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

coal-exit-path-capacity-closures-felixmatthes1

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

What can we learn from Germany’s experiment?

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

Today Germany, tomorrow the world?

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

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

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

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

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

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

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

Offshore Wind: The Next Big Thing

Offshore wind: The Next Big Thing
January 2020

Offshore wind has been beyond the horizon for energy planners everywhere but the North Sea, until the last few years. That’s no longer the case: offshore wind is becoming a major piece of the energy future for multiple countries and jurisdictions. Bloomberg reports offshore wind financings in 2019 came close to a whopping $30 billion, and in September 2019, the UK saw bids for offshore generation at under $0.05/KwH, cheaper than coal and natural gas alternatives. It’s a whole new water world out there.

Among the offshore wind projects reaching financial close in Q4 of 2019 alone were the 432MW Neart na Gaoithe array off the Scottish coast at $3.4 billion, the 376MW Formosa II Miaoli project off Taiwan at $2 billion and the 500MW Fuzhou Changle C installation in the East China Sea, at $1.5 billion. And in November Vattenfall was announced the winner of the Holland South Coast Phase II project, having already won Phase I; the 1.5 Gigawatt project will be Europe’s first subsidy-free offshore wind farm.

What happened? Only five years ago, offered prices for offshore wind tended around $0.15-0.20 a kilowatt-hour, well-above the price for competing sources and requiring government subsidies to proceed. Now larger and more efficient turbines, bigger projects, access to better offshore wind resources, and more developed supply chains have been driving prices down rapidly. Capex per MW of offshore wind capacity dropped from 4.5 Euros in 2015 to 2.5 Euros in 2018, a decline in costs of over 20% a year, according to Wind Europe. This has enabled the advantages of offshore turbines to come through: wind is much stronger off the coasts, and unlike wind over the continent, offshore breezes can be strong in the afternoon, matching the time when people are using the most electricity. Offshore turbines can also be located close to urban demand centers along the coasts, eliminating the need for new long-distance transmission lines

Offshore wind has already become the next big thing on the US East Coast. In November, New Jersey Governor Phil Murphy signed an executive order backing a goal of 7.5 GW of offshore wind by 2035, and said he expects that offshore wind could provide New Jersey with half of its electricity. Those figures would probably represent $15 billion of investment in New Jersey alone. In December, Connecticut awarded an 804 MW project with an (undisclosed) offset price “lower than any other publicly announced offshore wind project in North America,” expected to generate the equivalent of 14 percent of Connecticut’s total electricity supply. New York state announced in early January a 1 GW procurement of offshore wind in 2020, after 2019’s award of 1.7 GW of capacity, and announced a 9 GW offshore capacity target for 2035. And in early January Virginia’s Dominion Energy awarded a $7.8 billion, 2.64 GW offshore project – the largest currently on the drawing board in the US — to Siemens Gamesa.

The Land of Giants. With the average capital costs of offshore wind projects now easily in the $3-7 billion each range, the competitive landscape in the industry has evolved very differently than for the solar and onshore wind sectors. Solar in particular was characterized in its early days by many dozens of developers, at times trying to launch projects with capital costs of less than $50 million on a shoestring and selling them on to raise funding for their next investment. Not only are offshore wind turbines far larger than their onshore counterparts, but offshore wind players are far larger as well. The biggest current developers are Dong Energy in China, Scandinavians Ørsted (today’s market leader) and Vattenfall, and Iberdrola. All these have Balance Sheets with equity in the $100 billion-plus category. Vestas, Siemens Gamesa, and General Electric lead among turbine suppliers. An interesting sign of the times was the recent announcement from EDP of Portugal (itself partly owned by Three Gorges of China) and Engie that they would join forces in developing offshore wind projects, in order to gain the scale needed to compete.

Financing amounts are sufficiently forbidding that most developers have been financing projects on Balance Sheet, and until recently little commercial project finance debt has been available, outside of the policy banks in China for Chinese projects. The bulk of third-party financing for offshore wind has largely been in the form of ownership syndications and post-construction refinancing. The large scale of projects, while a major hurdle for many banks and smaller developers, is conversely an advantage for institutional investors such as pension funds and insurance companies, who have large minimum investment thresholds. These institutional investors have more typically invested in wind and solar through portfolio purchases rather than single project financing, as for example this week’s purchase of 50% of Total’s wind and solar portfolio by Caisse des Depots in France. From late 2018 European banks began to enter the UK offshore market with large amounts of non-recourse debt; as this model gains traction, it may allow smaller developers to become more active. As the sector is becoming more established, one can also expect the gradual development of a merchant risk-based financing model.

Offtake models have also been affected by the large scale of offshore wind developments. Corporate renewables, an increasingly big – and often well-priced – source of demand for solar and onshore wind projects, has not been a factor yet for offshore. In December, Ørsted announced the largest-ever corporate offshore wind deal, with German chemical company Covestro, for 100 MW.

What’s next? Tenders are planned in many countries, and are spreading beyond initial markets of Europe, the US and China. Vietnam, already with 99MW of offshore wind in place, is looking at what could become the world’s largest offshore wind farm with a capacity of 3,400 MW. ESMAP, a unit of the World Bank Group, published a study in October 2019 looking at eight non-OECD markets: Brazil, India, Morocco, the Philippines, South Africa, Sri Lanka, Turkey, and Vietnam. The ESMAP study estimated these eight markets alone have a technical capacity of over 3 Terrawatts – that’s 3,000 Gigawatts – for offshore wind. Globally, Wood Mackenzie expects 128 GW of offshore wind capacity to be built between 2020 and 2028, while Bloomberg New Energy Finance forecasts 188 GW of capacity to be installed by 2030. Those projections would imply capital investment in the sector in the range of $300 billion over the next decade. China is forecast to remain the largest country market, but with about half the global share that it has seen in solar (25% vs 50%).

Nonetheless, it may be difficult for offshore wind to gain more than a fraction of the geographic diversification that onshore wind, and particularly solar, have achieved. Many emerging markets are too small to consume the output of even a single offshore wind farm – at least in offshore’s current form. Construction timelines will also be an issue: an attraction of solar for lower-income, electricity-deficient countries is that solar farms can be financed and built fairly quickly, bringing new generation capacity on stream in a year or less after a country’s decision to proceed. An offshore wind farm typically takes five to ten years to develop. One possible model for smaller markets, for instance West Africa, might be multiple country offtakes.

A big factor in the longer-term development of offshore wind will be the feasibility – and cost – of floating wind farms. 99% of offshore wind farms to date are bottom-anchored, a big factor in the cost and scale of projects, and a limit on geographic deployment. Floating wind farms can in principle be deployed across many more areas, and could be built at a smaller scale. Indeed, the ESMAP emerging markets study puts 2/3 of identified potential offshore wind technical capacity in the floating, rather than fixed, category. IRENA’s late 2019 “Future of Wind” study forecasts floating platforms to make up a more modest 5-15% of total offshore capacity. Yet to date less than 50 MW of floating capacity is operational, so time will have to tell on this part of the technology. We’ll have to see how the winds blow…

Blue Coal ?

Blue Coal?
October 2019

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

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

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

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

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

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

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