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.

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…


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.



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 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.