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…


Checking in on Energy Storage Costs

Checking-in on Energy Storage costs
September 2019

Blink and you’ve missed something.

The energy storage market, seen as slowing down in 2018, has been on fire in 2019. If your understanding of batteries and storage is based on what you saw a year ago, it’s out of date. Actually, if your understanding is three months old, you’re still out of date! The size of energy-plus-storage projects has jumped, while their price has plunged.

Let’s look at the numbers. Based on the data collected by Bloomberg New Energy Finance in their annual battery price survey, the best available industry pricing benchmark, the average battery pack price fell 85% in the eight years from 2010, reaching an average of $176 per megawatt-hour in 2018 (see graphic).

Battery Prices 2010-2018

Battery technology has driven a price decline of the same magnitude as that which we’ve observed for solar energy. And as we’ve observed with solar, understanding the competitive position of an energy source using prices of the past, or even the present, leaves planners well out of date. Price being quoted for renewables-plus-storage of only five years ago, in the 20 cents per kilowatt-hour range – making them far more expensive than thermal electricity alternatives – have given way to prices 50-75% below this level, as we’ll see below. In only a few years, storage has gone from a niche concept to the new game in town. And much in the same way that solar energy price “records” have been being set continuously, each being greeted by disbelief that prices can reach this low, solar-plus-storage price records are now the stuff of headlines.

Four 2019 examples from different US states illustrate the bigger and cheaper trend.

  • Hawaii. In January 2019 the Hawaiian Public Utilities Commission approved contracts for six projects, with a capacity of 247 MW of power and 998 megawatt-hours of storage. This was the second largest “solar-plus-storage” project globally, behind only Moss Landing in California. The price range for the six projects came to between $0.08-$0.10/ KwH, prices cheaper than both Hawaii’s gas peaker plants and current cost of baseload fossil fuel plants (around 15 cents, given the high cost of transporting fuel to the islands). Developers include AES, Innergex, Clearway and 174 Power Global.
  • Florida. In late March 2019, Florida Power & Light Company announced it was building the world’s largest battery energy storage system, The FPL Manatee Energy Storage Center. At 409MW capacity, the project is claimed to be four times larger than the largest battery currently operating worldwide. FPLC also announced that the plant would help accelerate the decommissioning of two 1970s-era natural gas power units. Manatee Energy Storage Center would be linked to an existing PV plant, and start operating in 2021. FPL expects customers will save more than US$100 million through the change. This was a twist for FPLC’s existing modernization program which had focused on replacing oil-based power plants with U.S.-produced natural gas units. The natural-gas units were no longer the cheapest alternative for FPLC.
  • Nevada. Nevada in 2018 announced a huge solar-plus-storage procurement at then world-record prices, just below four cents a Kilowatt-hour. In June 2019, the Berkshire Hathaway-owned utility beat the one-year old record, announcing three new solar projects totaling 1,200 MWs paired with 590 MWs of storage. One of the projects, at 690 MWs, would blow past FPLC’s Manatee project to become the largest solar plant in the US. The winning bidders were developers 8minute Solar Energy, EDF Renewables and Quinbrook Infrastructure Partners with Arevia Power. 8minute said its project could run 65% of the time during peak summer hours, more than double the 30% average for solar in Nevada. 8minute said its project, at 300 megawatts of solar and 135-megawatts of 4-hour storage, will sell electricity at $0.035/KwH, a new world record low.
  • California. In early September, 2019, Los Angeles’ municipal utility approved the contract for Eland, a project for 400 MWs of solar power with up to 300 MWs and 1,200 MWHs of energy storage. Winning bidder 8minute offered a power-plus-storage rate of less $0.04/KwH for 25-years. The effective capacity of the project is expected to be 60%. Buyer LADWP is the largest municipal utility in the U.S., serving more than 4 million people.

With these there are now 9 energy-plus-storage projects underway with a capacity of over 100 MW (The Biggest Batteries Coming to a Grid Near You: the 100 MW Club is about to get a lot busier). With these new utility procurements dominating the news, the US is expected to regain the position of the world’s largest market for energy storage. 2019 is also widely expected to be the first year in which energy storage investments top $1 billion, from $500 million in 2018. Interestingly, the world’s largest market for storage in 2018 was South Korea, helped by a combination of strong incentives to reduce reliance on imported oil and coal and its well-developed domestic technology sector. South Korea procured over 1 GW of energy storage in 2018. However, fires related to Lithium-ion batteries have occurred at some 35 locations in the country, leading regulators to significantly slow down procurement. Problems appear to have been related to battery management systems rather than the batteries themselves, and similar issues have not been reported from other markets.

Interestingly as well, one can note that the world’s largest market for energy storage these last two years was not the one which might have been expected: China. In related technologies China has become by far and away the world’s biggest market for solar energy, and has an even larger lead in electric vehicles and vehicle batteries (almost 99% of the electric buses on the road today are in China). Yet China does not have a similar leadership position in solar-plus-storage – yet. China brought on-line a reported half-gigawatt of energy storage in 2018, equal to previous installed capacity, but well behind the US and South Korea. This surprising slow market development seems to stem from administrative regulations, which have compensated storage on an essentially cost-plus standalone basis, and the relative novelty of solar auctions to date in the country. With the announced administrative changes from China’s National Energy Administration, integrating storage into spot market pricing, demand is expected to jump substantially. Wood Mackenzie projects China’s cumulative energy storage capacity to grow to 12.5 gigawatts in 2024, a 25-fold increase in the current installed base, and about 14% of the projected global market in 2024. Looking at China’s track record in solar and in batteries, this may well be under-estimated. India also began to procure energy storage in 2017, and tendered for just under 100 MWs in March of this year. To date, India, though the second largest global market for solar power now, is a tiny player in storage. Lack of policy clarity has been a major issue, with a set of 2017 tenders having been cancelled without explanation early in 2019. Prime Minister Modi has launched a National Mission on Transformative Mobility and Battery Storage, under which a program will support the setting up of battery gigafactories across India. One can also expect the energy-plus-storage market in India to grow substantially.

Where to from here?
Looking forward, four key items stand out in attempting to foresee the renewables-plus-storage market of the future.
1) Still-lower prices and continued fast demand growth. Bloomberg NEF projects, based on a historically observed experience curve showing prices dropping 18% for every doubling of volume, that average prices of battery packs will fall from the current $176/KwH to around $94/Kwh by 2024 and $62/Kwh by 2030. Based on BNEF’s calculated present $0.06-0.07 premium to add four-hour storage to renewables, this would imply prices of energy-plus-storage falling below $0.06 per kilowatt-hour fairly widely – well below the cost of producing energy from greenfield coal plants. BNEF’s latest report on the battery market states “batteries co-located with solar or wind projects are starting to compete, in many markets and without subsidy, with coal- and gas-fired generation for the provision of ‘dispatchable power’ that can be delivered whenever the grid needs it (as opposed to only when the wind is blowing, or the sun is shining).” As we have been seeing already in several states, these declining prices will lead to rapid substitution – for investments in new electricity capacity — of renewables-plus-storage for fossil-fuels. Wood Mackenzie estimates that by 2024 global cumulative capex investment in energy storage will top $70 billion. This is a big deal, and a big disruption – or better put, yet another big disruption – for “traditional” energy markets. We can, in tandem with this growth, expect sharply declining demand for gas-plants (and so continued historically low natural gas prices). Wood Mackenzie projects that over 6 GW of planned gas-peaker capacity is at risk of cancellation in the US in the next few years; if storage costs continue to decline at double-digit levels annually, as they have done, then gas cancellations just in the US could run to 15 GW, or 80% of planned additions through 2026. In markets where natural gas is more expensive than it is in the US, substitution may occur even faster.
2) The hunt for the Next Big Thing continues. There is, of course, a catch to the rosy picture of renewables-plus-storage. It’s not in the well-publicized issue of the cost of cobalt, a key raw material for lithium-ion batteries of which more than half comes from war-torn Democratic Republic of Congo: costs of cobalt had spiked in 2016-7, but have fallen since as more efficient battery processes reduce demand. The catch is that lithium-ion batteries work well for providing critical four-hour storage, but not more. So while they are rapidly are becoming the best bet for dispatchable peak power, they don’t yet provide the equivalent of baseload, available 24-hour a day power. The search for the best longer-duration options continues. Pumped-hydro, which uses extra power to pump water uphill which can be used to turn a turbine and generate electricity when needed, is cost-effective but capital and space-intensive, so cannot be used in that many places. Flow battery technology gathers a lot of interest, but prices are prohibitive today for deployment, so much depends on whether the technology will gather the kind of cost-reduction which lithium-ion has.
3) Emerging Markets lag far behind. If we look at trends in relative economic growth, electricity consumption, and solar energy investments, we would expect that in the near future Emerging Markets would account for a large share, and certainly more than half, of demand for a centrally important energy technology such as storage. Yet unless we consider OECD-member South Korea to still be an Emerging Market, these countries account for less than 5% of today’s renewables-plus-storage market. By contrast, Emerging Markets account for roughly 2/3 of all solar and wind investment globally. The big bottleneck in emerging economies’ adoption of energy storage at scale is – and will continue to be — administrative capacity. We can see in the booming US market the amount of work which went into setting standards, regulations, and procurement programs. And we can see that in the two biggest emerging economies, China and India, policy choices have contributed to a slow rate of adoption to date. It seems that now China may have found a better procurement approach, but time will tell. We can also expect, as a corollary to this issue, that there will be a very large need for capacity-building, policy and technical support across emerging economies, to help them on the next stage of power availability and cost reductions. We can also expect that their success in doing so will have a very large impact on how big the storage market becomes, and how fast. Failure to get the procurement and regulatory environment right will likely mean a smaller global market than now estimated. Success, especially in China and India, may imply a significantly larger global market for battery storage than analysts are now projecting.
4) A push from policies? Wind and solar generation, in their early growth years, benefitted from significant policy support and subsidies. Now both technologies have reached the point that they are outcompeting alternatives on an economic basis without subsidies. In contrast, energy storage has benefitted significantly less from subsidies, as has renewables-plus-storage. For wind and solar in their early years, the medium-term question in forecasting market size was whether they would lose subsidies. For energy storage, a key medium-term question may be the exact opposite: will storage see new subsidies and policy support that it has not previously? If so, then the market may become much larger much faster than analysts presently predict. In an age of fiscal constraints and anti-renewables stances like that of the current US President and the oil and coal industries, this may seem far-fetched. But as Infrastructure Ideas has noted previously, energy policies may become substantially different in the future. Such a change depends largely on one’s views on the unfolding of climate change. If extreme weather events – floods, storms, wildfires and drought – continue to rapidly become more frequent and severe, as seems to be the case, and if data shows that keeping emissions even close to, let alone below, 2 degree warming scenarios has become essentially impossible, then the likelihood of more drastic climate-related policy actions increases substantially. Infrastructure Ideas sees this as the likeliest scenario, and probably within a five-year horizon from now. In such a scenario, “organic” growth of renewables and storage in electricity generation – as impressive as that growth now looks – may come to be seen as far short of what is wanted by voters and policy-makers. And in such a scenario, subsidies and other preferential polices favoring renewables-plus-storage combinations become one of the likeliest policy tools – further accelerating the current “organic” growth of storage. Stay tuned to the Weather Channel…

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.