February 10, 2017
ENERGY WATCH #1 by Karel Beckman
The OECD’s nuclear suicide
February 10, 2017
The journal Politico came out with a story last week screaming about “Russia’s nuclear attack on Europe”. This “attack” referred to the fact that Russian state-owned nuclear company Rosatom may get a contract to build the Paks II nuclear plant in Budapest, Hungary. Gee. And the Russkies are also building a new nuclear plant in Finland, Politico warns. Wow. I guess we should be stocking up on tin cans and head for our nuclear-protected cellars?
Apart from the annoying mix-up of nuclear power and nuclear arms implied by the word “attack”, does Politico not know that in the old Eastern Europe all nuclear power plants are of Russian design? There are Russian nuclear reactors in Bulgaria (2), Czech Republic (6), Finland (2), Hungary (4) and Slovakia (4, with two more being built). How would another Russian nuclear plant in Hungary suddenly turn into a “nuclear attack on Europe”?
Who does Politico suggest the Hungarians turn to if they want to build a new nuclear power plant? Areva? Toshiba?
Perhaps the EU should be glad that there still is a country, Russia, and a company, Rosatom, that is able to build nuclear power stations cost-effectively and on time. Politico charges that Rosatom’s projects are “often funded by subsidized Russian state loans”. Really? Wasn’t state-owned Areva recently bailed out by the French government to save it from bankruptcy? Isn’t Hinkley Point C getting built with massive government subsidies?
What is the real news is not that Rosatom wants to build nuclear power plants in the EU, but the fact that the EU, the US and Japan are busy committing nuclear suicide.
For starters, the French nuclear industry has taken a completely wrong turn with its EPR technology. I presume I don’t have to remind my readers of the Olkiluoto-3 disaster in Finland, which is now almost a decade late and three times over budget? Even Flamanville, on French home ground, is also more than three times over budget and many years late.
What is more, French technology is in trouble as faults have been discovered in the steel used by Areva in many of its nuclear reactors, including Flamanville.
The French and UK governments have now taken a terrific gamble, with the decision to let the French (EDF) build two EPR reactors at Hinkley Point C at an estimated cost of £18 billion.
Then there is the Japanese nuclear industry, which committed harakiri with Fukushima of course. But the fall-out from that is only now making itself felt in the export business. “Toshiba’s nuclear projects falling like a row of dominos”, nuclear energy author Dan Yurman wrote in his blog recently. The troubled Japanese company, which in December had to write down several billion dollars on its US nuclear activities, is now considering selling its US nuclear subsidiary Westinghouse.
It is also expected to announce its withdrawal from other projects worldwide, including the NuGen consortium which is planning to build a new nuclear power station in Cumbria in England. This could be a death blow to the project, since Toshiba’s partner in NuGen, French energy company Engie, has been wanting to get out of nuclear power anyway.
The possible death of NuGen (the company is trying to find new investors, in particular Kepco of South Korea) would be a blow to the planned UK nuclear renaissance, already in trouble over the cost of Hinkley Point C and the Euratom-Brexit. The UK is planning to build 13 new nuclear reactors across six sites from the mid-2020s onwards, including the 2 reactors at Hinkley Point C. EDF is supposed to build four of them, at Hinkley and at Sizewell in Suffolk, NuGen three AP1000s at Moorside in Cumbria, Hitachi four at Wlyfa Newydd on Anglesey and Oldbury in Gloucestershire. And two more reactors are planned at Bradwell. (Rosatom is not in the picture for any of those.)
Incidentally, Toshiba is also likely to announce its withdrawal from a project in India to build 6 nuclear reactors. As Dan Yurman writes: “After nine years of writing about the global nuclear industry, these development make for an unusually grim outlook. It’s a very big rock hitting the pond. Toshiba’s self-inflicted wounds will result in long lasting challenges to the future of the global nuclear energy industry.”
Yurman no doubt also has in mind the troubled state of the US nuclear industry, where one nuclear plant after the other is being shut down. Writing in World Nuclear News, Jarret Adams, a communications advisor to the nuclear industry, said that “The agreement to close prematurely the Indian Point Energy Center north of New York City felt like a gut punch. The latest in a string of closure announcements, Indian Point hurts so deeply because of its high-profile and proximity to the world’s leading financial centre.”
Adams notes that “as many as two-thirds of America’s 99 reactors could shut down by 2030. Today we are building four.” He calls this “nothing short of a national catastrophe”. His solution is for the nuclear industry to “invest in more marketing, advertising and public relations”. Nuclear energy, he writes, “is a premium product and must be sold as such.”
Not everyone will agree with that, but what is true is that the entire OECD nuclear sector is in dire straits. The well-informed anti-nuclear writer Jim Green, editor of Nuclear Monitor, writes in a recent review of nuclear developments in 2016 that “China, with 35 operable power reactors (up from 30 at the start of 2016), 22 under construction, and many more in the pipeline, remains the only country with significant nuclear expansion plans.”
He does warn that “Growth [in China] could be derailed by a serious accident, which is all the more likely because of China’s inadequate nuclear safety standards, inadequate regulation, lack of transparency, repression of whistleblowers, world’s worst insurance and liability arrangements, security risks and widespread corruption.”
A Chinese Chernobyl is, for the moment, simply speculation. The problems in the OECD’s nuclear sector are all too real.
ENERGY WATCH #2 by Karel Beckman
What’s the story on storage? Too complex for a headline
February 10, 2017
The Energy Storage World Forum, an annual event which will take place in May in Berlin, was kind enough recently to make available a free research 300-page report, the Energy Storage World Markets Report, produced by investment and advisory company Azure International (based in Beijing!). This report aims to provide insight into the worldwide market for energy storage, and I must say it does this quite successfully. If this is a topic that interests you, I recommend you get yourself a copy through the website of the Energy Storage World Forum (we have absolutely no relations with them at present!).
The best way to sum the report up is to say that there is really no way to sum it up. Storage (and we are talking here about grid-scale energy storage) is not one market, it is many markets. It is not one technology either, but many technologies.
As the report puts it: “The market for energy storage is inherently more derivative than those for renewable energy or other major clean energy categories. The market depends on the structure of wholesale power markets, the nature of local demand curves for different customers, the regional mix of electricity generation and transmission assets, and above all the pricing policies in place to govern how storage might be compensated and who might be eligible to receive compensation. Even policies designed to support energy storage are by necessity an order of magnitude more complicated than those to promote wind or solar. Add in the multiplicity of storage applications—renewable integration, micro grids, energy management, load shifting, frequency regulation, plus the potential to benefit from multiple revenue streams—and the overall picture at the global level takes on the level of complexity of the fine-grained structure of a carbon nanotube supercapacitor electrode.”
Thus, what the report looks at is now some overall market forecast, which is difficult to do at this stage, but instead to show “where energy storage makes most economic sense today and in the near future.”
The authors frankly admit that “Energy storage is still uneconomical for most applications, but understanding price points for market entry is the critical first step to evaluating investments in this sector as well as formulating market strategies.”
The report looks in depth at a number of specific markets (Germany, US, UK, France, Italy, Spain, Japan, South Korea, China, Australia, Europe) and at different “value applications”:
- Bulk Electricity Time Shifting
- Large-scale Wind Integration
- T&D (transmission and dispatch) Investment Deferral
- Residential, Commercial and Industrial Energy Management (TOU – time of use – Energy Management, Demand Charge Reduction, Power Reliability, Power Quality)
- Small-scale PV Integration
Here are some of the key findings, taken from the report:
- Australia and Italy showed that highest value for bulk electricity time shifting: Although advanced energy storage technologies will probably not be able to hit the price points to open up this market before 2020, these high value markets should be favorable for PHS [peak hour storage] development or stacked applications that derive only part of their value from wholesale energy arbitrage.
- Uncertainty looms regarding wholesale market pricing as the penetration of wind and solar increases: Peak and off-peak prices have been significantly affected by wind and solar selling into the wholesale market. Although, PHS may appear attractive based on 2013 modeling, many developers are unwilling to invest citing future uncertainty. In addition, the introduction of capacity payment to offset declining revenues from energy sales could create new opportunities for capacity based energy storage applications while driving up electricity price inflation.
- Wind integration opportunities remain elusive: Based on projections of wind integration costs from a number of international studies, Azure modeled the value of an energy-oriented energy storage system. The results show a clear trend of increasing benefits from 2013 to 2020, but the 2020 NPV benefit will likely be too low to attract energy storage investment without further subsidy support. Investment in new transmission, improved forecasting and revised generation scheduling practices should provide an effective means of integration in the short to medium term.
- Transmission and distribution upgrade deferral not attractive: Azure compared the conventional valuation approach (annualized avoided cost of transmission upgrade) to one based on the costs of using diesel in place of ES. The results clearly showed that diesel, due to its low CapEx and due to the application’s low utilization requirement, is a very cost effective means of delaying upgrades.
- Energy Management is Attractive but Only in Select Markets: In general, the value of energy storage increases closer to load. This is because ES can provide more benefits to upstream grid assets. Based on a survey of tariff structures within the 10 countries covered, Azure found that several countries (Australia, U.S., Japan) have currently attractive value propositions for TOU [time of use] energy management, demand charge management, or a hybrid of both. The value of this application is strongly dependent on retail pricing structures and does not necessarily exist in markets with high retail electricity tariffs, like Germany.
- Small-scale PV Integration close to Economic but not yet there: This application valuation, which considers the value of self-consumption versus grid discharge, is close to being economic with high-value cases in Germany, the U.K., Italy and Australia provided an NPV lifetime benefit over US$ 700/kWh. However, current system prices for lithium ion type systems are still above US$ 1000/kWh, so this market will take some time to develop. As electricity inflation continues and PV panel prices continue to decline, the value of this application should grow quickly over the coming years.
If you are not a storage expert, you may have difficulty translating some of this, so let me give you my headlines. “Demand response”, which you have heard a lot about (“energy management”): not attractive in Germany. “Solar-and-storage” (think Tesla Powerwall): not profitable yet, but getting there – in the UK, Italy and Australia. Wind-and-storage: still needs subsidies.
Some more findings. Italy and Germany are the leaders in the EU. The UK’s storage capacity “remains limited because a subsidy support structure has yet to be introduced”, but “beginning in 2020, small-scale PV integration is expected to become attractive without subsidy.”
On the EU overall, the report is quite critical. It notes that the potential of storage is very large, but “the lack of a consistent approach to storage may be the largest factor impeding the development of a European energy storage market.” That is to say, EU countries all have different market structures, policies and pricing systems, which make integrated solutions difficult.
Worse, policymakers have yet to put storage on an equal regulatory footing: “Early stage applications for storage typically include regulation services, T&D [transmission and distribution] deferral and spinning reserves, but across Europe is it unclear whether storage can consistently qualify for consideration in providing such services”, notes the report. “For integration of renewable energy and bulk power shifting/arbitrage, the situation is even less clear. Currently, storage cannot participate in wholesale power markets in Europe on an equal basis with generation, and storage solutions are not well integrated with transmission planning.”
Similarly, “for consumers integrating storage to reduce peak power demand, a more systematic approach is likely needed—for example, including both time-of-use tariffs and demand charges for all customers to ensure the introduction of renewable energy such as solar does not result in an unstable demand curve for certain regions.”
“For Europe as a whole, ENTSO-E [European network of transmission system operators] has stated that, ‘In terms of regulatory issues, open questions are related to which players (private market operators contributing to system optimization or regulated operators) shall own and manage storage facilities.’ The organization has also called for more large-scale ES demonstrations at the European level to validate both storage benefits and the potential asset ownership options for storage regulations.”
In other words: there is still a lot of work to do before storage can play the role it will need to play in the renewables-based, low-carbon energy system.
But this is policy speak of course. There is a lot of very practical information in the report as well.
ENERGY WATCH #3 by Karel Beckman
Lithium boom in Britain?
February 10, 2017
Speaking about storage: did you know that Cornwall in England could become a source for lithium? On January 19, the British company Cornish Lithium entered into an agreement with Canada’s Strongbow Exploration to explore and potentially develop lithium mining in Cornwall, writes Raimund Bleischwitz, Chair in Sustainable Global Resources at London’s university UCL on the website The Conversation.
“This is just a first step and it may be years before any lithium comes on stream”, notes Bleischwitz, “but it’s worth taking a look ahead.”
As everyone knows, the global lithium market is booming: the price has tripled from $6,000 per tonne at the end of 2015 to over $20,000 per tonne now. (By contrast: uranium – the basis of the troubled nuclear sector – was the worst performing commodity in 2016!)
Bleischwitz observes that “miners in Cornwall hope to produce lithium from hot spring brines while using geothermal energy extracted from these springs, which could drive processing costs down.” But he admits that “the project will not be without risks, including the possibility that radioactive radon could be released from granite. Also lithium recycling is not (yet) feasible, but recovering other materials from batteries such as magnesium, mercury and zinc may well trigger recycling efforts.”
According to Bleischwitz, “Cornish Lithium must now begin the crucial task of getting local people and other stakeholders on board – what’s known as a social license to operate. Cornwall already benefits from a thriving tourist industry. However, its centuries-long history as a mining region means it may well cope with the associated challenges. It has the potential to become a wellspring of new industrial activity, and Britain’s first lithium boom.”
ENERGY WATCH #4 by Karel Beckman
Brexit and security of gas supply: Nord Stream 2 to the UK instead of Germany?
February 10, 2017
Brexit is coming at a very sensitive time for the UK gas market, writes researcher Thierry Bros in an interesting new paper for the Oxford Institute for Energy Studies on the effect of Brexit on gas security of supply.
Bros notes that “UK North Sea gas production is in terminal decline and the main UK storage facility (Rough) is facing technical issues that will reduce its capacity with a possible extreme outcome, namely total decommissioning. These specific issues will make the Brexit negotiations even more difficult for the UK as far as gas is concerned.”
Both the UK and Ireland will see their “foreign dependency” grow strongly as a result of Brexit, notes Bros: “Up until this point, UK gas has been labelled EU gas and the UK has been able to access Norwegian gas (part of the European Economic Area) and EU piped domestic gas. As soon as Brexit is formally completed, the UK will still have its own domestic gas supply but will also need to access foreign gas (Norwegian and/or EU) to meet demand. By applying this definition, in 2015, 42 per cent of UK demand was ‘foreign’ gas. In the future, UK gas production is bound to decline and domestic shale gas production does not look promising enough to alter the trend. ‘Foreign dependency’ will also become a major issue for Ireland. Until now Ireland has been getting 97 per cent5 of its gas from the UK and in the internal market this was labelled EU gas, but post-Brexit, this same gas will be labelled ‘foreign’ gas. And with no regas capacity, all Irish ‘foreign’ gas will either have to be sourced from the UK or be transited via the UK.”
The EU will also become a little bit more “foreign dependent” as a result of Brexit, but not very much, as can be seen in this chart:
How worrisome is this? Well, as Bros puts it, “in a world awash with LNG”, no one is really too much concerned about “foreign dependence” at the moment. However, there are other aspects to take into account that make things not quite that simple.
First of all, the LNG supply and demand is expected to tighten in the 2020s.
Second, the position of the NBP – the UK’s gas hub National Balancing Point, the largest and most liquid in Europe – may be affected, as it will in effect become a regional hub. There are also various issues with the pipelines that connect the UK with the EU: Moffat to Ireland, Interconnector UK (IUK) with Belgium, and the Balgzand Bacton Line (BBL) from the Netherlands.
Today, the respective national regulatory authorities (Ofgem in the UK, CREG in Belgium, ACM in the Netherlands and CER in Ireland) are charged with regulating and supervising these pipelines under the EU Third Energy Package, but it is not clear yet whether the existing separate bilateral agreements will continue in order to comply with EU rules or whether the EU will step in and impose a single legal UK-EU agreement post-Brexit.
According to Bros, “the UK’s interest in keeping integrated energy markets is obvious as it will limit the NBP from de-coupling too much from the [Dutch gas hub] TTF. On the other hand, why would the EU provide a level playing field to the UK when it is not part of the same club any longer? Some countries in Europe could be tempted to impose severe and costly regulation on EU-UK pipelines to push up energy prices in the UK allowing de facto the EU to be slightly more competitive.”
In addition, Bros points out, “the EU Commission does not want see any gross welfare loss in the future, and could possibly request some form of solidarity mechanism for Ireland to be levied on EU gas exports. It is possible that the EU could add some fees (at EU transmission system operator level) or taxes when piped gas is exported (to the UK), with little risk of retaliation as the UK is now an energy importer. The issue of Irish security of supply is going to be extremely important during negotiations and could be used by the UK to try to preserve the status quo as this is the cheapest way to provide security of supply to Irish consumers.”
Third, the UK has very little storage capacity (just 6.6% of annual UK demand). Ireland, which would be cut off from the European mainland, has even less.
Under normal circumstances, writes Bros, the UK imports gas in winter due to its limited storage capacity. There is no reason why the country can’t continue to do so after Brexit. But in case of an emergency, the situation becomes different: the UK will then no longer be able to rely on the EU’s solidarity mechanism. Ireland may be entitled to EU solidarity, but it’s going to be difficult to implement this, since Ireland will be disconnected from the EU.
Now this assumes that Rough is working at capacity, but according to Bros, “Rough is facing a series of outages and the final outcome is still unknown (as of January 2017 … Should Rough be closed down, UK storage capacity would represent a mere 1.8 per cent of its annual consumption. The reduction in storage capacity will hugely impact on the UK and Ireland’s security of supply during winter.”
Bros notes that there are “three options are open to mitigate this risk:
- “A rational outcome for the UK and Ireland to secure winter supply could be to use both regas (in competition with the EU) and the ample EU-26 storage especially that is located in NWE (29.9 per cent capacity of EU-26 annual demand) thanks to the BBL and IUK interconnectors.
- Alternatively, as there is no guarantee that the UK will be included in the EU-26 solidarity mechanism, new underground storage could be built in the UK. However as Europe has a surplus of storage capacity, winter-summer spreads are too low to allow the financing of new facilities. It would therefore require a policy decision to push companies to invest in new facilities as they would normally more likely wait for future NBP winter-summer spreads to increase before taking a Final Investment Decision.
- A third possibility is that Gazprom could offer to go back to its original plan and change Nord Stream 2 to Brexit Stream, channeling gas straight to the UK, which could, post-2019, be free of the EU Third Energy Package.”
This is what I call a creative solution! A Brexit Stream “would allow both Russia and the UK to strike a deal which would give security of demand and security of supply (and this goes back to first conclusion with the UK needing to strike deals with energy producers). With TurkStream and Brexit Stream, the Ukraine transit risk would only be an issue for the EU-26 alone.”
For this solution to work, however, better geopolitical relations are needed between the UK and Russia. Not for nothing does Bros note that “The UK needs to reshape its energy diplomacy that has in the last decade increasingly been handled by Brussels, with a concomitant decrease in knowledge and power within the UK.” Surely the Oxford Institute for Energy Studies has the knowledge needed to assist the UK government with this new gas diplomacy.
ENERGY WATCH #5 by Karel Beckman
More wind power? Half of EU member states did not build a single turbine
February 10, 2017
Wind power accounted for 51% of all new power installations in 2016, connecting a total of 12.5 GW to the grid across the 28 EU Member States – 10,923 MW in onshore and 1,567 MW offshore, according to the latest figures from trade association WindEurope.
Total wind capacity in Europe now stands at 153.7 GW. Wind energy covered 10.4% of Europe’s electricity needs last year. Germany installed the most new wind power: 44% of the EU total. Five Member States had a record year: France, the Netherlands, Finland, Ireland and Lithuania. Renewables altogether accounted for 86% of new EU power plant installations in 2016 – 21.1GW of 24.5 GW.
Investment in new onshore and offshore wind farms reached a record €27.5bn. Offshore wind investments rose 39% year on year to €18.2bn, while onshore investments were down 29% at €9.3bn.
According to Giles Dickson, Chief Executive Officer of WindEurope, the wind energy sector now provides 330,000 jobs and “billions of euros of European exports”.
So is the wind sector happy? Not really. “With all the talk about the transition to low-carbon, things should be looking good long-term for the wind industry in Europe. But they’re not”, says Dickson. “Government policy on energy across Europe is less clear and ambitious than it was a few years ago. Only 7 out of 28 EU Member States have targets and policies in place for renewables beyond 2020. The transition from feed-in tariffs to auctions has been less smooth than we hoped. We still have dysfunctional electricity markets that are not fit for renewables. And we’re lacking long-term price signals to support investment.”
Dickson also noted that “We saw strong expansion in Germany in 2016 but growth remains uneven geographically. Over half the Member States invested nothing in wind energy last year. Policy is key, especially when we look at the longer term. The Member States also need to start defining in their National Energy and Climate Plans how they will deliver the transition at national level. The Clean Energy Package is the blueprint for this. The Council and the European Parliament need to start working seriously on the Commission’s proposals.”
WindEurope launched a Daily Wind tool on which people can see how much wind energy in Europe is generated each day, the share of wind in the power mix (in each country) and how well Europe’s wind farms are performing.
ENERGY WATCH #6 by Karel Beckman
Record number of solar jobs in U.S.
February 10, 2017
The number of jobs created to make, sell and install solar panels in the U.S. grew at a record pace last year, much faster than the overall American economy. The new figures were issued on Tuesday by the Solar Foundation in its seventh annual report on the state of the industry. It found that there were 260,077 solar workers as of November 2016, which represents nearly 25 percent growth from the amount of solar jobs recorded the year prior. In comparison, jobs in the overall U.S. economy grew at a rate of 1.45 percent.
Last year’s solar market performance made 2016 the fourth consecutive year that U.S. solar jobs grew by 20 percent or more, the report found. It also made for some eye-popping figures, like how 1 out of every 50 new jobs, or 2 percent of new jobs, created in the U.S. in 2016 came from the solar industry.
The U.S. solar industry now employs more workers than natural gas, more than double the number of workers in the coal industry, and in comparison to other energy sectors, employment in solar trails only the U.S. oil industry.
The Solar Foundation’s jobs numbers contrast a bit with the solar jobs figures that came out of the Department of Energy’s U.S. Energy and Employment Report in January, which found that there were 374,000 solar workers in 2016. But that data included workers that spent some portion of their time in solar, while the Solar Foundation’s new report only focused on workers that primarily work in solar.
The Solar Foundation estimates that job growth rate will be closer to 10 percent for 2017, leading to 286,000 solar workers by the end of this year. The number of solar panels installed across the U.S. in 2017 is expected to be slightly lower than it was in 2016.