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!

Renewable PPAs and Political risk: Spain revisited

Renewable PPAs and Political Risk: Spain Revisited
February 2020

In 2014, Spain – then Europe’s second-largest market for wind and solar electricity — shocked renewable investors and developers by retroactively and unilaterally revising the prices it paid for recently installed solar electricity farms. From a generous FIT (Feed-in-Tariff) system, Spain went to a “reasonable rate of return” approach, with far lower compensation to owners. This was a new kind of political risk coming to life. The outraged renewables industry hoped that either Spain would quickly change its mind, or quickly become so isolated from foreign investment that it would be forced to change its mind at least before long. Neither of the hoped-for paths materialized. Yet somehow, a few years later, in 2019, Spain returned to the forefront, drawing in over $8 billion of investment into new wind and solar generating capacity – more than any other country in Europe. What happened? And what have we learned?

Spain and solar

Since Spain’s 2014 decision to unilaterally change solar PPAs, arbitrators and lawyers have been busy. Some 50 cases arguing breach of contract – seeking redress on the order of $7 billion — have been making their way along in courts and arbitration processes. In 3 of the past 6 years, Spain has topped the list of offenders in the proceedings of ICSID — the International Center for Settlement of Investment Disputes, part of the World Bank Group. Spanish courts, unsurprisingly, have tended to support the government’s actions, while arbitration results have been for the most part going against it. About a dozen decisions have been rendered against Spain, with the current sum of awards at around $800 million. But Spain has yet to pay any of these awards out. Some of the ICSID arbitration decisions have sided with Spain, and in many cases awards have fallen far short of amounts being sought by investors (for example, SolEs Badajoz, whose case was decided in July 2019, was awarded Eur 41 million compared to a request for Eur 98 million). During the 2014-2018 period, investment in the Spanish electricity sector fell off considerably.

Then came 2019, and both the tariff and legal situation for the Spanish renewables sector changed. In November, Spain approved a royal decree floated earlier in the year which offers investors economic incentives that can only be accessed if the pending cases are dropped. The new law will allow investors to either stick with existing renumeration or opt to maintain a 7.39% rate of return for the next two regulatory periods, which ends in 2031. For Spanish players, this is cause for celebration: guaranteed income for 12 years, in exchange for giving up court cases which have not been going anywhere. Prior to the change, the then in force framework would have likely lowered existing tariff returns by about 40% at the start of 2020. For foreign investors pushing arbitration, the trade-off is less attractive (see Investors Still Waging War with Spain Over Retroactive Cuts), and many seem ready to continue to fight for compensation, though decisions remain to be announced. What was clear was the market reaction: new generation investment in Spain’s renewables soared, with the country overtaking Germany and the UK as Europe’s biggest market for 2019.

Clear winners in all this? Lawyers. And risk managers urging caution on investors. The main protagonists? The original investors – at least international investors, not the Spanish investors who can only sue through Spanish courts — may get some compensation, but much later than they’d hoped, and less than they hoped. Or they may not. Definitely not clear winners. Possibly clear losers, probably partly losers. The Spanish government saved a lot of money and hasn’t had to pay any of it back – yet. They may have to pay a chunk of it back soon. Or not. The economy slowed down for a few years, but it was doing that anyway due to the fiscal imbalances which led to the unilateral revisions in the first place, and now investment is back. And of course the current government is not the one who adopted the belligerent policy towards the renewables industry. Neither clear winners or losers, possibly partly winners (if they wind up paying very little of the) arbitration awards and requests, possibly partly losers (if they’re eventually forced to pay out large amounts).

So what to make of Spain’s highly-publicized breaking of contracts? In some ways, it may be surprising that more countries have not sought to follow Spain’s path. Leaving aside the specifics of Spain’s 2013-2014 budget problems which triggered the contract revisions, the underlying issue with solar contracts facing Spain at the time is one that is widely shared: technology improvement. When the price of a product falls a long way – as has been the case for wind and solar electricity – those who commit to buying the product on a long-term, fixed-price contract early wind up paying a lot more for the product than they would have if they had waited, and more than others who signed contracts later are doing. Spain is 2014 was paying anywhere from 30 to 50% more for solar power, with contracts signed in 2009-2010, than it would have been doing if it had signed those contracts in 2014, or than other countries then signing those contracts would be paying. The temptation for a buyer – in this case Spain — to find a way to get the new price, rather than the old price, is high. When the buyer is a new government, happy to cast blame on its predecessors, that temptation gets even higher. This has been the big political risk for renewables generation. But a great many countries have faced this temptation, and almost all have chosen to honor their old higher-priced contracts. The only similar attempt in recent years has come in the last year in Andhra Pradesh, where the incoming state government is seeking to force the lowering of tariffs – or cancellation – for 2-7-year-old solar projects contracted by the previous State Government. The new government, through the state-owned distribution companies, is seeking cuts up to 60% in agreed tariffs, and to cut 15 years off PPA lengths. A special case is in the offing in California, where the strength of renewable PPA offtake contracts are being tested in bankruptcy court – with the wildfire-driven bankruptcy of utility PG&E leading to attempts to shed various liabilities, including offtake contracts, to get PG&E out of bankrupcy. To date, California courts have affirmed the validity of the PPAs. Many eyes are on South Africa, whose situation today looks like that of Spain in 2014 taken to an extreme: a new government, an essentially bankrupt state-owned utility, large budget deficits, and renewable offtake contracts up to nine years old – several for power at well over $0.10 a kilowatt-hour, more than triple what new PPAs would be likely to cost. The Government of South Africa would love to change its older renewable energy offtake contracts, but so far has taken a different tack than Spain: it has offered project owners the option of voluntarily reducing the payments they receive per kilowatt-hour of electricity generated in return for longer deals and upgraded projects boasting more generation capacity.

Spain’s walking away from contracts was feared by renewable energy investors in 2014 to be the prelude to an epidemic. That has not happened. Political risk, even in the face of continued falling prices and widespread potential temptation, has remained low. The counterweight to the temptation, it can be argued, has been the source of the temptation itself. As wind and solar prices continue to fall – joined now by battery prices — and continue to present more opportunities for countries to reduce energy costs, staying in the market for technology is more important to most governments. In infrastructure, politics often trumps common sense. In renewable energy, technology is trumping politics.

Infrastructure in 2020: Ten Predictions

Infrastructure in 2020: ten predictions
January 2020

1. Wind and solar keep growing.

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

2. Offshore wind is the new big thing

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

3. Challenges mount for power grids and utilities

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

4. Non-lithium batteries get serious

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

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

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

6. Emissions-free city zones multiply

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

7. Unilateral “100% renewables” commitments multiply

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

8. Financing premiums appear for climate risks

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

9. Delivery vehicles become the new EV focus

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

10. More alarms over hacking of infrastructure

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



Asia’s Energy Transformation: India

Asia’s Energy Transformation: India
August 2019

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

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

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

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

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

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

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

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

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

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

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

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


And the Prices Keep Falling (II)

And the Prices Keep Falling (part II)

In the first of this two-part post, And the Prices Keep Falling, Infrastructure Ideas highlighted the hugely positive side of this Summer’s remarkable solar auctions in Brazil and Portugal. With the price of new solar – and wind – generating capacity continuing to fall to record low levels, energy is getting cheaper for nearly all. And cleaner.

Yet there is a dark side.

Today’s post outlines some less positive consequences of these falling prices for two important sets of players. And we don’t mean the fossil fuel industry. Falling prices have downside for solar investors and lenders, and – surprisingly – for some of the countries who most need solar and wind power.

Falling costs (as distinct from prices) can affect industries in different ways. In some industries, producers are able to maintain previous price levels, or at least ensure that prices fall more slowly than costs. This drives higher profits, and is naturally the outcome to which most firms aspire. In other industries, prices fall as fast, or even faster than costs. This is the kind of outcome which disproportionately benefits consumers. As economists would frame it, consumers are capturing most – if not all – the benefits of falling costs. The solar and wind generation sectors are an example of the latter.

Why this should be the case is a good question, but one with a simple answer. Consumers, and consuming countries, have captured most or all of the benefits of falling solar and wind costs for one reason: competitive auctions. The across-the-board switch from older power procurement methods — negotiated contracts, and feed-in-tariffs – to competitive price-based auctions was pioneered in large Emerging Markets, notably Brazil and South Africa, in the early 2010s. now it is highly unusual to see utility-scale procurement on any different basis. A Bloomberg New Energy Finance analysis in 2016 found that the switch to auctions was responsible for as much of the price decline in countries which adopted them as were technology cost declines.

But what is great for buyers is becoming increasingly problematic for investors and lenders. Prices in recent PPA auctions are falling to such levels that little room is left for either unforeseen operational risks, or for the cost of capital. Already in mid-2018, UK consulting firm Cornwall Insight projected that unsubsidized solar projects would be unviable by 2030 (what happens when renewables eat their own profits?), in this case because of pushing wholesale prices in the UK down so far. Wood Mackenzie’s Emma Foehringer Merchant wrote back in January 2019 of a “finance bubble” in the solar industry. Looking at results of recent solar auctions, Merchant noted “A flood of new investors, like pension funds and insurance companies, now view solar as a stable asset. That “wall of money” going after a smaller pool of projects has created a market so competitive that many sponsors are willing to accept lower-than-average returns. Power-purchase agreement prices have also fallen to new lows, and contract terms have gotten shorter. Industry financial experts say, taken together, those trends have led to a mispricing of risk.” The chorus has become louder after this Summer’s below 2 cents/KwH auctions. A piece by Wood Mackenzie’s Jason Deign (Key to those record-low solar bids?) looked at the mechanics of bidders’ approaches to preparing these super-low priced bids, and concluded that bidders were offering very low prices for Power Purchase Agreements with the idea that they could sell power for higher prices in later years in merchant markets. An assumption which, given the recent history of how fast prices are falling, would seem highly unrealistic.

These emerging risk profiles for new solar and wind generation investments are getting further and further away from “traditional” electricity industry risk profiles, which assumed steady long-term revenues and predictably stable conditions for the life of 15 to 20-year loans. Normally lenders to such projects would adjust to higher risk and lower predictability by charging higher interest rates, but with prices falling so far and margins getting squeezed, new projects and owners have no room to accommodate higher rates – and indeed are strongly pressuring lenders to squeeze margins further down. A likely outcome? Lower profits and higher risks for renewable energy lending portfolios.

As solar becomes a larger and larger – and lower cost — market, one would think this is all good news for industry players, though we see it is not. And there’s another group for who one would think it’s all good news – but it’s not – or at least not for some of the group. This group? Low-income countries.

In principle low-income countries are the potentially biggest beneficiaries of low-cost wind and solar. Often the countries with the biggest electricity deficits, the highest costs of power, and the least money with which to add generation capacity, low-income countries stand to benefit disproportionately from plunging solar costs. And those that move to join those countries establishing competitive procurement auctions will do just that – benefit disproportionately. Their development and economic gains will be huge. The catch? Not all will manage to do so.

The difficulty for many low-income countries lies in organizing access to this new bounty of cheap solar (and wind). It will not happen by itself. Implementing competitive auctions is not an impossible task, but it does require organization, administrative competency, and ability to deliver on a process once it is announced. Many low-income countries face two important hurdles to achieve this. The first hurdle is weak administrative capacity to organize auctions. Auctions, after all, often differ radically from existing procurement mechanisms in many low-income countries, and a poorly handled process can significantly limit interest from solar companies – leading to less competition and unnecessarily high bid prices. This is a hurdle which can be surmounted, but often requires assistance from advisers who have done it before. The second hurdle is probably the higher. The second hurdle is the power of vested interests who benefit from existing arrangements – often high cost, inefficient arrangements. Foremost among these may be the national monopoly utility, and those in charge of supplying raw material – oil or coal – to the existing generation fleet. These vested interests may have significant political power and influence, enough to derail the implementation of administratively complex and novel competitive auctions for solar.

For countries which fail to overcome these two hurdles, the future is bleak. In a world where more and more countries are able to achieve lower energy costs through procurement of low-priced wind and solar generation, those countries whose energy costs are dominated by high-priced, “traditional” thermal electricity resources will become less and less competitive, and fall further behind their neighbors. Failure to join the low-cost renewable energy club will carry very high opportunity costs, both in terms of development, and of foregone economic competitiveness.

So cheer low cost solar. And encourage all not to be left behind.

Asia’s Energy Transformation: Indonesia

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

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

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

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

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

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

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

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

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

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

Asia’s Energy Transformation: Bangladesh

Asia’s Energy Transformation: Bangladesh

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

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

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

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

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

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

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

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

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

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

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

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

Asia’s Energy Transition: Pakistan

Asia’s Energy Transition: Pakistan

This is the first of a series on the energy transition in Asia’s largest economies. Asia is the most important global market for energy consumption, investment, and greenhouse-gas emissions. Asia is also a region in the midst of a large-scale energy transition, whose pattern and evolution remains to be determined. How this energy transition evolves has more importance to the future of climate change, and to the future of energy investments, than that of any other region. Infrastructure Ideas will focus in turn on the state-of-play in this transition in several of Asia’s big economies, starting with Pakistan.

A few numbers illustrate the importance of Asia in the energy world. Between economic growth and connecting the underserved (just under 500 million of the 1 million people without access to reliable electricity are in Asia), the region dwarfs all others in expected energy consumption growth. Bloomberg New Energy Finance projects that, in Asia, over $5 trillion will be invested in power generation capacity from now to 2050, over $180 billion per annum. Asia is expected to account for nearly 50% of all such investment globally.

Power investments by region to 2050
Asia-Pacific also accounts now for about half of all Greenhouse Gas emissions, and in line with growing energy consumption, the growth rate of emissions from Asia, at over 3% p.a., is triple the growth rate of emissions of the rest of the world. Behind this high share of GHG emissions is not only overall energy consumption growth, but more importantly how much of electricity production in Asia is coal-fired. 67% of all coal-fired generation capacity is in Asia, and essentially all of the growth in new coal-fired capacity globally is in Asia. So as well-reported, Asia is the key battleground for future GHG emissions evolution, and for the scope of future climate change. How decisions are made about more coal, less coal, and the speed of adoption of renewable energy sources will have a disproportionate effect on the rest of the world and future generations.

Pakistan is a key player in Asia’s energy transition, albeit one drawing far less attention than China and India. This is somewhat surprising, given that Pakistan is the world’s 6th most populous country, with about 200 million people. Pakistan also has plans for larger investment levels in new power capacity than all but a handful of countries, and some plans to increase coal-fired electricity production by over 500%… so an important country on many fronts! Let’s look more closely at the state of play.

For a country with as many people as Pakistan, and which has recorded solid economic growth for decades, power production is remarkably low. Total generation capacity today in the country is only just over 25 Gigawatts (GWs), and per capita electricity consumption is only 2/3 of that in India, and only 1/3 of that in Egypt. While 90 million people have gained access to formal electricity over the last two decades, there are still some 50 million people without access, and industry is hampered by extensive load-shedding, often over 10 hours a day. Thus increasing power availability has been a high government priority in Pakistan for a long time, and one can expect that the country will add substantial new production capacity over the next couple of decades.

Pakistan’s power sector is of high importance – for provision of basic services, supporting economic and job growth, and for public finances. It also has some oddities. One is the unusually high share of oil-fired generation: about 1/3 of Pakistan’s electricity is produced from either diesel or fuel oil, probably the highest ratio – by far – of any of the world’s largest countries. This has had and continues to have major negative consequences in terms of higher costs, high GHG and particulate emissions, and large trade deficits (Pakistan imports most of its oil). Hydropower and natural gas-fired generation each account for just under 30% of production, coal about 5% and nuclear a little less. Another oddity (shared with a small handful of its Asian neighbors) is the high percentage of power production which is government-run, at about 50%. A 2018 World Bank Report (“In the Dark”, World Bank 2018) estimated that these public sector plants use 17-28% more fuel per output than their private sector counterparts, and that mostly public policy and management inefficiencies in electricity cost the country 6.5% of GDP annually.

In the last five years, Pakistan has entered into a new energy transition, whose direction and outcomes remain very uncertain. The key energy policy decisions going forward for Pakistan revolve around its current transition, and the 20-30 GW of new electricity production capacity it seeks to add.

It has been clear to the Government that continued reliance on oil-fired generation is financially impossible. Yet between the choices of coal, gas, hydropower, wind and solar, the right direction has not been obvious. Development of more coal-fired capacity has had many supporters in Pakistan: the country has large domestic coal resources, coal has historically been a cheap source of fuel, and some government plans have called for coal to assume an up to 30% share of electricity production – compared to about 5% today. Domestic natural gas became important in the decades after independence, but domestic fields are essentially exhausted, and new imports of gas – while important – are at best replacing previous domestic sources, and are in part diverted to domestic fertilizer production. So the share of gas-fired power production is likely to decline substantially. Hydropower may be an important part of the solution. Pakistan has important developed and undeveloped hydropower potential. In the early decades after independence, large-scale dams were constructed by the country’s public sector utility: its chronic losses and mismanagement have essentially made further investment out of the question. Pakistan has instead turned to auctions, whose winners have to date been dominated by Chinese firms, notably China Three Gorges. This holds some promise of relatively low cost and low emission capacity growth, but contentious water ownership issues close to the border with India, climate-change related hydrological uncertainties, and the sheer scale of the new plants likely limit how big a role they play in overall country capacity growth. This leaves the key uncertainties of the transition between large-scale coal-fired generation increases, and accelerated development of wind and solar resources.

While not an early adopter, Pakistan has begun to replicate the renewable energy auction procurement mechanisms which have so strongly impacted many emerging markets. Roughly 40 new wind and solar farms have been provided PPAs, and at prices (US$0.05-0.07) well below Pakistan’s average power costs.

Pakistan power costsOn the one hand, renewable energy is now the cheapest form of electricity generation in Pakistan. This should not be unexpected, given how falling costs have made wind and solar the cheapest options for new capacity in much of the world – accounting for over 50% of all new electricity capacity additions worldwide in 2017 – and Pakistan’s plentiful wind and solar resources. On the other hand, renewable energy proponents carry limited political weight in Pakistan. Proponents of expanded use of coal, by contrast, carry substantial weight – both domestic supporters who would like to see investment in local coal deposits such as the massive Thar field, and external financiers looking to sell coal and coal-fired generation plants – mainly from China. The Chief Minister of Sindh Province, where many of the country’s coal deposits lie, stated in early March that the long-delayed Thar coal-fired plant would “start soon.” Given Pakistan’s long-unstable domestic politics, and perennial foreign-exchange problems, the verdict on the country’s energy transition remains out. The implications are significant – building another 15-20 GW of coal-fired generation in Pakistan in the coming decades could add up to 100 million tons to annual CO2 emissions – an increase of 40% over Pakistan’s current CO2 emissions, and roughly what 25 million cars produce. And, given the contrary trends in prices, probably leave system-wide power costs at least 20% higher than they could be. This is clearly a country whose energy politics bear watching.

Some positive signs? In January, the 1,320 MW, the proposed Rahim Yar Khan imported coal-fired power plant was shelved, reportedly over concerns about increased fossil fuel imports. And in February, during a State visit, Saudi Arabia’s ACWA power, one of the largest wind and solar generation companies globally, was quoted as seeing the potential for up to $4 billion in investment in renewables in Pakistan.

Renewable Energy as 2019 begins: Winners and Losers

Renewable Energy as 2019 begins: Winner and Losers

Renewable energy continued in 2018 as the largest segment of infrastructure financing globally. Utility-scale wind and solar, and rooftop solar new capacity installations grew again. The days of double-digit industry growth in capacity, however, seem to be past, and with falling costs the total capital going to renewables is clearly at a plateau. There’s good news and bad news for different parties, and in this column infrastructure ideas offers a guide to the winners and losers of the moment.

The numbers for 2018
Based on just-released figures from Bloomberg New Energy Finance, the fastest to estimate year-end numbers, “clean-energy investment” was down 8% from 2017, yet nonetheless, at $332 billion, over $300 billion for the fifth straight year. Within those numbers, investment in all segments were up except for two: small scale-hydro, and solar power generation – the latter seeming counter-intuitive but we’ll unpack it below. Onshore wind investment rose slightly, 2% to $101 billion, while offshore wind came into its own for the first time, recording $28 billion in investment. Bio-mass, waste-to-energy, biofuels and geothermal were all up from 2017, yet together accounting for only about 3% of total investment. Investment in solar, interestingly, fell from $160 billion to $131 billion. Two big factors seem to be have driven the plunge: one visible everywhere, with the cost per unit of new solar capacity continuing to fall be double-digits in 2018, and overall capacity installed still grew from 2017 though the costs of this declined; the other factor being visible mostly in China, where big policy changes led to a 32% fall in new renewables investment in the world’s largest solar market. India’s market, arguably the fastest-growing market in the world from 2015-2017 for new solar financings, also cooled off, with clean energy (mostly solar) financings falling from $13 billion to $11 billion.


1. Investors looking for RE assets. For investment funds and others who built up capacity to finance renewable energy, assets are increasingly there. The $300 billion in new financing in 2018 means renewables continue to be the biggest game in town, with over $2 trillion having been invested in these sectors in the past decade. And while the overall global market may have been slightly negative, the sharp slowdown in China obscures good growth outside of China: non-Chinese investment in wind and solar increased over 20%, and the non-Chinese share of the global RE market went from 45% to 60%. Given how relatively closed the Chinese market has been to external investment, this means the effective pool of investable RE assets has grown significantly.

2. Offshore wind in OECD. Offshore wind, a curiosity only a few years ago, is at $28 billion now the fourth largest segment of clean energy – after onshore wind, utility solar and rooftop solar. It dwarfs other clean energy segments such as geothermal, biomass and small hydro. For many infrastructure funds, offshore wind has another attraction: large average project size. So while there remain a limited number of offshore assets, and they are all limited to either OECD markets or China, this is clearly now a legitimate and important sub-market.

3. Policy-makers. The continued declines in the costs of solar, and to an extent onshore wind capacity, are great news for energy sector policy-makers. In particular, energy sector policy-makers in developing countries – whose task is to address insufficient power capacity and/or high-cost electricity systems – have now at their disposal the means to increase power availability and to sharply cut the average generation costs of power in their economies. Wind and solar power at below 6 to 7 cents a kilowatt/hour – or even below 3 cents are a number of markets are achieving – means new capacity at less than half the average tariff in many developing countries. And everywhere, policy-makers concerned over greenhouse gas emissions and looking to meet “green” policy mandates have well-established options for their electric systems.

4. Solar plus storage advocates. Not yet in the numbers but worth a flag. While new capacity of solar-plus-storage systems account for less than 1% of total 2018 investment, and does not show up in global clean energy numbers yet, one can see this is just around the corner. With energy storage costs plummeting as fast as solar panel costs did a decade ago, we are already beginning to see the first solar-plus-storage tenders emerge with costs competitive with or bettering the costs of new thermal power capacity. Look for this segment to be bigger than biofuels or geothermal within the next 1-2 years, and larger than the offshore wind segment within 5-10 years.


1. Investors looking for RE assets. If the big loser sounds like the big winner, that’s because they are one and the same. There are indeed more and more renewable energy assets available in which to invest, and a greater share of these is “market,” as the non-China share of this segment is where growth is concentrated. At the same time, though, price and risk of RE assets are an increasing concern for investors. Solar power-purchase agreements (PPAs) are increasingly being priced so low that making money has become an increasingly tricky proposition. Or put another way, the benefits of falling RE costs are being largely apportioned to consumers (and policy-makers), leaving thin margins to compensate providers of capital. And at the same time, many markets are seeing shorter PPAs being offered, meaning new solar and wind farms have shorter periods of guaranteed returns, and face the prospect of yet lower-priced competitors when the guaranteed-return periods come to an end. And more investors are coming late to the party, further pressuring returns. Assets are there for investors, but making good returns from them will require being smart.

2. China RE portfolios. If you had financed wind and solar assets in China during the past decade – and if those assets were not being curtailed by the Chinese grid (a big “if”) – things were not too bad through 2017. Not only has China been by far the world’s largest renewable energy market for several years, it’s also paid some of the highest prices for renewable-generated power through Feed-in Tariffs. The kind of wind and solar auctions which have been so effective at driving down the cost of new capacity in Brazil, India and South Africa, among other markets, have come late to China. But with the big policy changes enacted in 2018, China was more disrupted than any other market. Going forward it will be a new game, with China adopting the auction approach – post the 2018 disruptions, this is likely to be good news all around: cheaper RE power across China, increasingly competitive with existing coal-fired capacity and less likely to be curtailed. It will mean, however, a new approach to the Chinese market.

3. Thermal power. New RE capacity additions were more than double the roughly 70-80 GW of new thermal power capacity added worldwide in 2018. Even with the growth of natural-gas fired capacity in the US and China, thermal power is becoming a shrinking market for operators and investors. And this is with continued historically-low natural gas prices, in the $3-5 mmbtu range. Driving this shrinkage is the combination of declining cost-competitiveness of thermal power, as technology improvements are unable to drive down costs as fast they are declining in renewables and energy storage, and policy preferences in many markets. It’s not going to get any better, though natural gas – especially in combined-cycle plants, is increasingly outcompeting coal-fired generation.

4. Small hydro. In the days of early enthusiasm for renewables, hydropower enjoyed a boost in popularity, riding on the same wave propelling new technologies. Small run-of-the-river hydropower plants especially, seen as more environmentally-friendly than large dam-reliant hydropower, began to attract considerable interest from operators and investors. The 2018 numbers show that small hydro has been left far behind by its former renewable peers, wind and solar. At only $1.7 billion, about ½ of 1% of all clean energy investments, and one of the only categories declining in 2018, it looks like the lost stepchild.

5. Proponents of a 1.5-degree limit. For those concerned about climate change, and especially those wanting to see the world on a course to limit global warming to 1.5 degrees, 2018 was not a good year. Yes, renewable energy capacity is growing, and new investments are almost double those in fossil fuel-based power generation. But even with this, the penetration level of renewables in the overall share of power generation is too low for a 1.5-degree warming scenario. Given that the rate of increase of renewable generation has slowed, it becomes harder to see climate mitigation efforts relying just on the economics of new generation facilities. So expect, therefore, both to see escalating effects of global warming – more extreme weather events, more calls for climate adaptation investments – and growing odds of a major discontinuity in energy policies down the road. One good bet: growing interest in funding decommissioning of fossil-fuel generation – watch this space for a forthcoming analysis of the topic.